Building energy system with load-following-block resource allocation

ABSTRACT

A building energy system includes equipment operable to consume, store, or generate one or more resources, a utility connection configured to obtain, from a utility provider, a first resource subject to a load-following-block rate structure and provide the first resource to the equipment, and a controller. The controller provides an objective function indicating a total value of purchasing the first resource from the utility provider over a plurality of time steps. The objective function includes a first term representing a load-following-block of the first resource from the utility provider as being sourced from a first supplier at a fixed rate and a second term representing a remainder of the first resource from the utility provider as being sourced from a second supplier at a variable rate. The controller controls the equipment based on a result of an optimization of the objective function.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.16/223,746, filed Dec. 18, 2018, the entire disclosure of which isincorporated by reference herein.

BACKGROUND

The present disclosure relates generally to a central energy facility,and more particularly to cost optimization for a central energy facilitysubject to a block-and-index rate structure or a load-following-blockrate structure. Minimizing costs may be a goal of building systems andenergy systems. New pricing schemes such as block-and-index ratestructures or load-following-block rate structures may require solutionsfor operating equipment to achieve optimal costs under such pricingschemes.

SUMMARY

One embodiment of the invention is a building energy system. Thebuilding energy system includes equipment operable to consume, store, orgenerate one or more resources and a utility connection configured toobtain, from a utility provider, a first resource of the one or moreresources subject to a block-and-index rate structure and provide thefirst resource to the equipment. The building energy system alsoincludes a controller configured to obtain a cost function that includesa total cost of purchasing the first resource from the utility providerat each of a plurality of time steps of an optimization period. The costfunction represents a block of the at least one of energy or power fromthe utility provider as being sourced from a first supplier at a fixedrate and represents a remainder of the first resource from the utilityprovider as being sourced from a second supplier at a variable rate. Thecontroller is also configured to optimize the cost function subject toone or more constraints to generate values for one or more decisionvariables that indicate an amount of the one or more resources topurchase, store, generate, or consume at each of the plurality of timesteps of the optimization period. The controller is also configured tocontrol the equipment to achieve the values of the one or more decisionvariables at each of the plurality of time steps of the optimizationperiod.

In some embodiments, the controller is configured to set the fixed rateto zero. In some embodiments, the first resource is metered in units ofenergy. The cost function and the one or more constraints represent thefirst supplier as an energy storage device having a capacity equal to asize of the block.

In some embodiments, the first resource includes natural gas. In someembodiments, the first resource is metered in units of power. The one ormore constraints require that an amount of the first resource purchasedat the fixed rate at each time step is less than or equal to a size ofthe block.

In some embodiments, the first resource includes electricity.

In some embodiments, a size of the block is selectable at a beginning ofa calendar period. The controller is configured to determine an optimalsize of the block. The controller is configured to automatically selectthe size of the block and provide an indication of the optimal size ofthe block to the utility provider.

In some embodiments, a size of the block is user selectable.

Another implementation of the present disclosure is a method forallocating resources in a building energy system. The method includesoperating equipment to consume, store, or generate one or moreresources, receiving a first resource of the one or more resources froma utility provider subject to a block-and-index rate structure,providing the first resource to the equipment, and allocating the one ormore resources amongst the equipment. Allocating the one or moreresources amongst the equipment includes obtaining a cost function thatincludes a total cost of purchasing the first resource from the utilityprovider at each of a plurality of time steps of an optimization period.The cost function represents a block of the first resource from theutility provider as sourced from a first supplier at a fixed rate andrepresenting a remainder of the first resource from the utility provideras sourced from a second supplier at a variable rate. Allocating the oneor more resources amongst the equipment also includes performing anoptimization process for the cost function subject to one or moreconstraints to generate values for one or more decision variables thatindicate an amount of the one or more resources to purchase, store,generate, or consume at each of the plurality of time steps of theoptimization period. The method includes controlling the equipment toachieve the values of the one or more decision variables at each of theplurality of time steps of the optimization period.

In some embodiments, the controller is configured to set the fixed rateto zero. In some embodiments, the first resource is metered in units ofenergy. Optimizing the cost function includes representing the firstsupplier as an energy storage device having a capacity equal to a sizeof the block.

In some embodiments, the first resource includes natural gas. In someembodiments, the first resource is metered in units of power. In someembodiments, the one or more constraints require that an amount of thefirst resource purchased at the fixed rate at each time step is lessthan or equal to a size of the block.

In some embodiments, the first resource includes electricity. The methodincludes determining an optimal size of the block.

In some embodiments, a size of the block is selectable at a beginning ofa calendar period. The method includes automatically selecting the sizeof the block and providing an indication of the optimal size of theblock to the utility provider.

In some embodiments, the method includes receiving an input of a size ofthe block from a user.

Another implementation of the present disclosure is a method forallocating resources in a building energy system. The method includesoperating equipment to consume, store, or generate one or more resourcesand receiving a first resource of the one or more resources from autility provider subject to a block-and-index rate structure. Theblock-and-index rate structure assigns a fixed rate to a block of thefirst resource and a variable rate to a remainder of the first resource.The method also includes selecting an optimal size of the block byobtaining a cost function that includes a total cost of purchasing thefirst resource from the utility provider over an upcoming time period,the cost function comprising a decision variable treating a size of theblock as a peak demand auxiliary variable and optimizing the costfunction to determine the optimal size of the block as the size of theblock that minimizes the total cost of purchasing the first resourcesfrom the utility provider for the upcoming time period. The method alsoincludes providing an indication of the optimal size of the block to theutility provider to enroll in the block-and-index rate structure for theupcoming time period with the block having the optimal size andcontrolling the equipment to consume a total amount of the firstresource. The block is priced at the fixed rate and the remainder ispriced at the variable rate. The block has the optimal size.

In some embodiments, optimizing the cost function includes generating aplurality of scenarios of possible loads and possible variable rates forthe upcoming time period. The optimal size of the block minimizes thetotal cost of purchasing the first resource over all of the plurality ofscenarios. In some embodiments, generating the plurality of possibleloads and possible index rates for the time period includes storing ahistory of past scenarios comprising actual values for historical loadsand historical variable rates and at least one of sampling the possibleloads and possible index rates from the history of past scenarios; orgenerating an estimated distribution based on the history of pastscenarios and sampling the possible loads and possible variable ratesfrom the estimated distribution.

In some embodiments, optimizing the cost function to determine theoptimal size of the block includes selecting a plurality of possibleblock sizes, evaluating the cost function for each possible block sizeto determine a simulated cost for each of the possible block sizes,fitting a model to the simulated costs, determining the a size of theblock that minimizes the predicted total cost by minimizing the modelwith respect to the size of the block, and selecting the optimal size ofthe block as the size of the block that minimizes the predicted totalcost. In some embodiments, minimizing the model with respect to the sizeof the block comprises performing at least one of gradient descent, agolden section search, a Fibonacci search, or Newton's method.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram of a frequency response optimization system,according to an exemplary embodiment.

FIG. 2 is a graph of a regulation signal which may be provided to thesystem of FIG. 1 and a frequency response signal which may be generatedby the system of FIG. 1, according to an exemplary embodiment.

FIG. 3 is a block diagram of a photovoltaic energy system configured tosimultaneously perform both ramp rate control and frequency regulationwhile maintaining the state-of-charge of a battery within a desiredrange, according to an exemplary embodiment.

FIG. 4 is a drawing illustrating the electric supply to an energy gridand electric demand from the energy grid which must be balanced in orderto maintain the grid frequency, according to an exemplary embodiment.

FIG. 5 is a block diagram of an energy storage system including thermalenergy storage and electrical energy storage, according to an exemplaryembodiment.

FIG. 6 is block diagram of an energy storage controller which may beused to operate the energy storage system of FIG. 5, according to anexemplary embodiment.

FIG. 7 is a block diagram of a planning tool which can be used todetermine the benefits of investing in a battery asset and calculatevarious financial metrics associated with the investment, according toan exemplary embodiment.

FIG. 8 is a drawing illustrating the operation of the planning tool ofFIG. 7, according to an exemplary embodiment.

FIG. 9 is a first graphical illustration of a block-and-index ratestructure, according to an exemplary embodiment.

FIG. 10 is a second graphical illustration of a block-and-index ratestructure, according to an exemplary embodiment.

FIG. 11 is a graphical illustration of a load-following block ratestructure, according to an exemplary embodiment.

FIG. 12 is a block diagram of a building energy system under a powerblock-and-index rate structure, according to an exemplary embodiment.

FIG. 13 is a block diagram of a building energy system under an energyblock-and-index rate structure, according to an exemplary embodiment.

FIG. 14 is a block diagram of a building energy system under aload-following-block rate structure, according to an exemplaryembodiment.

FIG. 15 is a flowchart of a first process for determining an optimalhedging percentage for a load-following-block rate structure.

FIG. 16 is a flowchart of a second process for determining an optimalhedging percentage for a load-following-block rate structure.

DETAILED DESCRIPTION

Referring generally to the FIGURES, a building energy system withstochastic model predictive control and demand charge incorporation isshown according to various exemplary embodiments. The building energysystem can include some or all of the components of a frequency responseoptimization system 100, photovoltaic energy system 300, energy storagesystem 500, energy storage controller 506, and/or planning tool 702, asdescribed with reference to FIGS. 1-8. The stochastic model predictivecontrol and demand charge incorporation features are described in detailwith reference to FIGS. 9-17.

Frequency Response Optimization System

Referring now to FIG. 1, a frequency response optimization system 100 isshown, according to an exemplary embodiment. System 100 is shown toinclude a campus 102 and an energy grid 104. Campus 102 may include oneor more buildings 116 that receive power from energy grid 104. Buildings116 may include equipment or devices that consume electricity duringoperation. For example, buildings 116 may include HVAC equipment,lighting equipment, security equipment, communications equipment,vending machines, computers, electronics, elevators, or other types ofbuilding equipment.

In some embodiments, buildings 116 are served by a building managementsystem (BMS). A BMS is, in general, a system of devices configured tocontrol, monitor, and manage equipment in or around a building orbuilding area. A BMS can include, for example, a HVAC system, a securitysystem, a lighting system, a fire alerting system, and/or any othersystem that is capable of managing building functions or devices. Anexemplary building management system which may be used to monitor andcontrol buildings 116 is described in U.S. patent application Ser. No.14/717,593 filed May 20, 2015, the entire disclosure of which isincorporated by reference herein.

In some embodiments, campus 102 includes a central plant 118. Centralplant 118 may include one or more subplants that consume resources fromutilities (e.g., water, natural gas, electricity, etc.) to satisfy theloads of buildings 116. For example, central plant 118 may include aheater subplant, a heat recovery chiller subplant, a chiller subplant, acooling tower subplant, a hot thermal energy storage (TES) subplant, anda cold thermal energy storage (TES) subplant, a steam subplant, and/orany other type of subplant configured to serve buildings 116. Thesubplants may be configured to convert input resources (e.g.,electricity, water, natural gas, etc.) into output resources (e.g., coldwater, hot water, chilled air, heated air, etc.) that are provided tobuildings 116. An exemplary central plant which may be used to satisfythe loads of buildings 116 is described U.S. patent application Ser. No.14/634,609 filed Feb. 27, 2015, the entire disclosure of which isincorporated by reference herein.

In some embodiments, campus 102 includes energy generation 120. Energygeneration 120 may be configured to generate energy that can be used bybuildings 116, used by central plant 118, and/or provided to energy grid104. In some embodiments, energy generation 120 generates electricity.For example, energy generation 120 may include an electric power plant,a photovoltaic energy field, or other types of systems or devices thatgenerate electricity. The electricity generated by energy generation 120can be used internally by campus 102 (e.g., by buildings 116 and/orcentral plant 118) to decrease the amount of electric power that campus102 receives from outside sources such as energy grid 104 or battery108. If the amount of electricity generated by energy generation 120exceeds the electric power demand of campus 102, the excess electricpower can be provided to energy grid 104 or stored in battery 108. Thepower output of campus 102 is shown in FIG. 1 as P_(campus). P_(campus)may be positive if campus 102 is outputting electric power or negativeif campus 102 is receiving electric power.

Still referring to FIG. 1, system 100 is shown to include a powerinverter 106 and a battery 108. Power inverter 106 may be configured toconvert electric power between direct current (DC) and alternatingcurrent (AC). For example, battery 108 may be configured to store andoutput DC power, whereas energy grid 104 and campus 102 may beconfigured to consume and generate AC power. Power inverter 106 may beused to convert DC power from battery 108 into a sinusoidal AC outputsynchronized to the grid frequency of energy grid 104. Power inverter106 may also be used to convert AC power from campus 102 or energy grid104 into DC power that can be stored in battery 108. The power output ofbattery 108 is shown as P_(bat). P_(bat) may be positive if battery 108is providing power to power inverter 106 or negative if battery 108 isreceiving power from power inverter 106.

In some embodiments, power inverter 106 receives a DC power output frombattery 108 and converts the DC power output to an AC power output. TheAC power output can be used to satisfy the energy load of campus 102and/or can be provided to energy grid 104. Power inverter 106 maysynchronize the frequency of the AC power output with that of energygrid 104 (e.g., 50 Hz or 60 Hz) using a local oscillator and may limitthe voltage of the AC power output to no higher than the grid voltage.In some embodiments, power inverter 106 is a resonant inverter thatincludes or uses LC circuits to remove the harmonics from a simplesquare wave in order to achieve a sine wave matching the frequency ofenergy grid 104. In various embodiments, power inverter 106 may operateusing high-frequency transformers, low-frequency transformers, orwithout transformers. Low-frequency transformers may convert the DCoutput from battery 108 directly to the AC output provided to energygrid 104. High-frequency transformers may employ a multi-step processthat involves converting the DC output to high-frequency AC, then backto DC, and then finally to the AC output provided to energy grid 104.

System 100 is shown to include a point of interconnection (POI) 110. POI110 is the point at which campus 102, energy grid 104, and powerinverter 106 are electrically connected. The power supplied to POI 110from power inverter 106 is shown as P_(sup). P_(sup) may be defined asP_(bat) P_(loss), where P_(batt) is the battery power and P_(loss) isthe power loss in the battery system (e.g., losses in power inverter 106and/or battery 108). P_(bat) and P_(sup) may be positive if powerinverter 106 is providing power to POI 110 or negative if power inverter106 is receiving power from POI 110. P_(campus) and P_(sup) combine atPOI 110 to form P_(POI). P_(POI) may be defined as the power provided toenergy grid 104 from POI 110. P_(POI) may be positive if POI 110 isproviding power to energy grid 104 or negative if POI 110 is receivingpower from energy grid 104.

Still referring to FIG. 1, system 100 is shown to include a frequencyresponse controller 112. Controller 112 may be configured to generateand provide power setpoints to power inverter 106. Power inverter 106may use the power setpoints to control the amount of power P_(sup)provided to POI 110 or drawn from POI 110. For example, power inverter106 may be configured to draw power from POI 110 and store the power inbattery 108 in response to receiving a negative power setpoint fromcontroller 112. Conversely, power inverter 106 may be configured to drawpower from battery 108 and provide the power to POI 110 in response toreceiving a positive power setpoint from controller 112. The magnitudeof the power setpoint may define the amount of power P_(sup) provided toor from power inverter 106. Controller 112 may be configured to generateand provide power setpoints that optimize the value of operating system100 over a time horizon.

In some embodiments, frequency response controller 112 uses powerinverter 106 and battery 108 to perform frequency regulation for energygrid 104. Frequency regulation is the process of maintaining thestability of the grid frequency (e.g., 60 Hz in the United States). Thegrid frequency may remain stable and balanced as long as the totalelectric supply and demand of energy grid 104 are balanced. Anydeviation from that balance may result in a deviation of the gridfrequency from its desirable value. For example, an increase in demandmay cause the grid frequency to decrease, whereas an increase in supplymay cause the grid frequency to increase. Frequency response controller112 may be configured to offset a fluctuation in the grid frequency bycausing power inverter 106 to supply energy from battery 108 to energygrid 104 (e.g., to offset a decrease in grid frequency) or store energyfrom energy grid 104 in battery 108 (e.g., to offset an increase in gridfrequency).

In some embodiments, frequency response controller 112 uses powerinverter 106 and battery 108 to perform load shifting for campus 102.For example, controller 112 may cause power inverter 106 to store energyin battery 108 when energy prices are low and retrieve energy frombattery 108 when energy prices are high in order to reduce the cost ofelectricity required to power campus 102. Load shifting may also allowsystem 100 reduce the demand charge incurred. Demand charge is anadditional charge imposed by some utility providers based on the maximumpower consumption during an applicable demand charge period. Forexample, a demand charge rate may be specified in terms of dollars perunit of power (e.g., $/kW) and may be multiplied by the peak power usage(e.g., kW) during a demand charge period to calculate the demand charge.Load shifting may allow system 100 to smooth momentary spikes in theelectric demand of campus 102 by drawing energy from battery 108 inorder to reduce peak power draw from energy grid 104, thereby decreasingthe demand charge incurred.

Still referring to FIG. 1, system 100 is shown to include an incentiveprovider 114. Incentive provider 114 may be a utility (e.g., an electricutility), a regional transmission organization (RTO), an independentsystem operator (ISO), or any other entity that provides incentives forperforming frequency regulation. For example, incentive provider 114 mayprovide system 100 with monetary incentives for participating in afrequency response program. In order to participate in the frequencyresponse program, system 100 may maintain a reserve capacity of storedenergy (e.g., in battery 108) that can be provided to energy grid 104.System 100 may also maintain the capacity to draw energy from energygrid 104 and store the energy in battery 108. Reserving both of thesecapacities may be accomplished by managing the state-of-charge ofbattery 108.

Frequency response controller 112 may provide incentive provider 114with a price bid and a capability bid. The price bid may include a priceper unit power (e.g., $/MW) for reserving or storing power that allowssystem 100 to participate in a frequency response program offered byincentive provider 114. The price per unit power bid by frequencyresponse controller 112 is referred to herein as the “capability price.”The price bid may also include a price for actual performance, referredto herein as the “performance price.” The capability bid may define anamount of power (e.g., MW) that system 100 will reserve or store inbattery 108 to perform frequency response, referred to herein as the“capability bid.”

Incentive provider 114 may provide frequency response controller 112with a capability clearing price CP_(cap), a performance clearing priceCP_(perf), and a regulation award Reg_(award), which correspond to thecapability price, the performance price, and the capability bid,respectively. In some embodiments, CP_(cap), CP_(perf), and Reg_(award)are the same as the corresponding bids placed by controller 112. Inother embodiments, CP_(cap), CP_(perf), and Reg_(award) may not be thesame as the bids placed by controller 112. For example, CP_(cap),CP_(perf), and Reg_(award) may be generated by incentive provider 114based on bids received from multiple participants in the frequencyresponse program. Controller 112 may use CP_(cap), CP_(perf), andReg_(award) to perform frequency regulation.

Frequency response controller 112 is shown receiving a regulation signalfrom incentive provider 114. The regulation signal may specify a portionof the regulation award Reg_(award) that frequency response controller112 is to add or remove from energy grid 104. In some embodiments, theregulation signal is a normalized signal (e.g., between −1 and 1)specifying a proportion of Reg_(award). Positive values of theregulation signal may indicate an amount of power to add to energy grid104, whereas negative values of the regulation signal may indicate anamount of power to remove from energy grid 104.

Frequency response controller 112 may respond to the regulation signalby generating an optimal power setpoint for power inverter 106. Theoptimal power setpoint may take into account both the potential revenuefrom participating in the frequency response program and the costs ofparticipation. Costs of participation may include, for example, amonetized cost of battery degradation as well as the energy and demandcharges that will be incurred. The optimization may be performed usingsequential quadratic programming, dynamic programming, or any otheroptimization technique.

In some embodiments, controller 112 uses a battery life model toquantify and monetize battery degradation as a function of the powersetpoints provided to power inverter 106. Advantageously, the batterylife model allows controller 112 to perform an optimization that weighsthe revenue generation potential of participating in the frequencyresponse program against the cost of battery degradation and other costsof participation (e.g., less battery power available for campus 102,increased electricity costs, etc.). An exemplary regulation signal andpower response are described in greater detail with reference to FIG. 2.

Referring now to FIG. 2, a pair of frequency response graphs 200 and 250are shown, according to an exemplary embodiment. Graph 200 illustrates aregulation signal Reg_(signal) 202 as a function of time. Reg_(signal)202 is shown as a normalized signal ranging from −1 to 1 (i.e.,−1≤Reg_(signal)≤1). Reg_(signal) 202 may be generated by incentiveprovider 114 and provided to frequency response controller 112.Reg_(signal) 202 may define a proportion of the regulation awardReg_(award) 254 that controller 112 is to add or remove from energy grid104, relative to a baseline value referred to as the midpoint b 256. Forexample, if the value of Reg_(award) 254 is 10 MW, a regulation signalvalue of 0.5 (i.e., Reg_(signal)=0.5) may indicate that system 100 isrequested to add 5 MW of power at POI 110 relative to midpoint b (e.g.,P_(POI)*=10 MW×0.5+b), whereas a regulation signal value of −0.3 mayindicate that system 100 is requested to remove 3 MW of power from POI110 relative to midpoint b (e.g., P_(POI)*=10 MW×−0.3+b).

Graph 250 illustrates the desired interconnection power P_(POI)* 252 asa function of time. P_(POI)* 252 may be calculated by frequency responsecontroller 112 based on Reg_(signal) 202, Reg_(award) 254, and amidpoint b 256. For example, controller 112 may calculate P_(POI)* 252using the following equation:

P _(POI)*=Reg_(award)×Reg_(signal) +b

where P_(POI)* represents the desired power at POI 110 (e.g.,P_(POI)*=P_(sup)+P_(campus)) and b is the midpoint. Midpoint b may bedefined (e.g., set or optimized) by controller 112 and may represent themidpoint of regulation around which the load is modified in response toReg_(signal) 202. Optimal adjustment of midpoint b may allow controller112 to actively participate in the frequency response market while alsotaking into account the energy and demand charge that will be incurred.

In order to participate in the frequency response market, controller 112may perform several tasks. Controller 112 may generate a price bid(e.g., $/MW) that includes the capability price and the performanceprice. In some embodiments, controller 112 sends the price bid toincentive provider 114 at approximately 15:30 each day and the price bidremains in effect for the entirety of the next day. Prior to beginning afrequency response period, controller 112 may generate the capabilitybid (e.g., MW) and send the capability bid to incentive provider 114. Insome embodiments, controller 112 generates and sends the capability bidto incentive provider 114 approximately 1.5 hours before a frequencyresponse period begins. In an exemplary embodiment, each frequencyresponse period has a duration of one hour; however, it is contemplatedthat frequency response periods may have any duration.

At the start of each frequency response period, controller 112 maygenerate the midpoint b around which controller 112 plans to performfrequency regulation. In some embodiments, controller 112 generates amidpoint b that will maintain battery 108 at a constant state-of-charge(SOC) (i.e. a midpoint that will result in battery 108 having the sameSOC at the beginning and end of the frequency response period). In otherembodiments, controller 112 generates midpoint b using an optimizationprocedure that allows the SOC of battery 108 to have different values atthe beginning and end of the frequency response period. For example,controller 112 may use the SOC of battery 108 as a constrained variablethat depends on midpoint b in order to optimize a value function thattakes into account frequency response revenue, energy costs, and thecost of battery degradation. Exemplary techniques for calculating and/oroptimizing midpoint b under both the constant SOC scenario and thevariable SOC scenario are described in detail in U.S. patent applicationSer. No. 15/247,883 filed Aug. 25, 2016, U.S. patent application Ser.No. 15/247,885 filed Aug. 25, 2016, and U.S. patent application Ser. No.15/247,886 filed Aug. 25, 2016. The entire disclosure of each of thesepatent applications is incorporated by reference herein.

During each frequency response period, controller 112 may periodicallygenerate a power setpoint for power inverter 106. For example,controller 112 may generate a power setpoint for each time step in thefrequency response period. In some embodiments, controller 112 generatesthe power setpoints using the equation:

P _(POI)*=Reg_(award)×Reg_(signal) +b

where P_(POI)*=P_(sup)+P_(campus). Positive values of P_(POI)* indicateenergy flow from POI 110 to energy grid 104. Positive values of P_(sup)and P_(campus) indicate energy flow to POI 110 from power inverter 106and campus 102, respectively.

In other embodiments, controller 112 generates the power setpoints usingthe equation:

P _(POI)*=Reg_(award)×Res_(FR) +b

where Res_(FR) is an optimal frequency response generated by optimizinga value function. Controller 112 may subtract P_(campus) from P_(POI)*to generate the power setpoint for power inverter 106 (i.e.,P_(sup)=P_(POI)*−P_(campus)). The power setpoint for power inverter 106indicates the amount of power that power inverter 106 is to add to POI110 (if the power setpoint is positive) or remove from POI 110 (if thepower setpoint is negative). Exemplary techniques which can be used bycontroller 112 to calculate power inverter setpoints are described indetail in U.S. patent application Ser. No. 15/247,793 filed Aug. 25,2016, U.S. patent application Ser. No. 15/247,784 filed Aug. 25, 2016,and U.S. patent application Ser. No. 15/247,777 filed Aug. 25, 2016. Theentire disclosure of each of these patent applications is incorporatedby reference herein.Photovoltaic Energy System with Frequency Regulation and Ramp RateControl

Referring now to FIGS. 3-4, a photovoltaic energy system 300 that usesbattery storage to simultaneously perform both ramp rate control andfrequency regulation is shown, according to an exemplary embodiment.Ramp rate control is the process of offsetting ramp rates (i.e.,increases or decreases in the power output of an energy system such as aphotovoltaic energy system) that fall outside of compliance limitsdetermined by the electric power authority overseeing the energy grid.Ramp rate control typically requires the use of an energy source thatallows for offsetting ramp rates by either supplying additional power tothe grid or consuming more power from the grid. In some instances, afacility is penalized for failing to comply with ramp rate requirements.

Frequency regulation is the process of maintaining the stability of thegrid frequency (e.g., 60 Hz in the United States). As shown in FIG. 4,the grid frequency may remain balanced at 60 Hz as long as there is abalance between the demand from the energy grid and the supply to theenergy grid. An increase in demand yields a decrease in grid frequency,whereas an increase in supply yields an increase in grid frequency.During a fluctuation of the grid frequency, system 300 may offset thefluctuation by either drawing more energy from the energy grid (e.g., ifthe grid frequency is too high) or by providing energy to the energygrid (e.g., if the grid frequency is too low). Advantageously, system300 may use battery storage in combination with photovoltaic power toperform frequency regulation while simultaneously complying with ramprate requirements and maintaining the state-of-charge of the batterystorage within a predetermined desirable range.

Referring particularly to FIG. 3, system 300 is shown to include aphotovoltaic (PV) field 302, a PV field power inverter 304, a battery306, a battery power inverter 308, a point of interconnection (POI) 310,and an energy grid 312. PV field 302 may include a collection ofphotovoltaic cells. The photovoltaic cells are configured to convertsolar energy (i.e., sunlight) into electricity using a photovoltaicmaterial such as monocrystalline silicon, polycrystalline silicon,amorphous silicon, cadmium telluride, copper indium galliumselenide/sulfide, or other materials that exhibit the photovoltaiceffect. In some embodiments, the photovoltaic cells are contained withinpackaged assemblies that form solar panels. Each solar panel may includea plurality of linked photovoltaic cells. The solar panels may combineto form a photovoltaic array.

PV field 302 may have any of a variety of sizes and/or locations. Insome embodiments, PV field 302 is part of a large-scale photovoltaicpower station (e.g., a solar park or farm) capable of providing anenergy supply to a large number of consumers. When implemented as partof a large-scale system, PV field 302 may cover multiple hectares andmay have power outputs of tens or hundreds of megawatts. In otherembodiments, PV field 302 may cover a smaller area and may have arelatively lesser power output (e.g., between one and ten megawatts,less than one megawatt, etc.). For example, PV field 302 may be part ofa rooftop-mounted system capable of providing enough electricity topower a single home or building. It is contemplated that PV field 302may have any size, scale, and/or power output, as may be desirable indifferent implementations.

PV field 302 may generate a direct current (DC) output that depends onthe intensity and/or directness of the sunlight to which the solarpanels are exposed. The directness of the sunlight may depend on theangle of incidence of the sunlight relative to the surfaces of the solarpanels. The intensity of the sunlight may be affected by a variety ofenvironmental factors such as the time of day (e.g., sunrises andsunsets) and weather variables such as clouds that cast shadows upon PVfield 302. When PV field 302 is partially or completely covered byshadow, the power output of PV field 302 (i.e., PV field power P_(PV))may drop as a result of the decrease in solar intensity.

In some embodiments, PV field 302 is configured to maximize solar energycollection. For example, PV field 302 may include a solar tracker (e.g.,a GPS tracker, a sunlight sensor, etc.) that adjusts the angle of thesolar panels so that the solar panels are aimed directly at the sunthroughout the day. The solar tracker may allow the solar panels toreceive direct sunlight for a greater portion of the day and mayincrease the total amount of power produced by PV field 302. In someembodiments, PV field 302 includes a collection of mirrors, lenses, orsolar concentrators configured to direct and/or concentrate sunlight onthe solar panels. The energy generated by PV field 302 may be stored inbattery 306 or provided to energy grid 312.

Still referring to FIG. 3, system 300 is shown to include a PV fieldpower inverter 304. Power inverter 304 may be configured to convert theDC output of PV field 302 P_(PV) into an alternating current (AC) outputthat can be fed into energy grid 312 or used by a local (e.g., off-grid)electrical network. For example, power inverter 304 may be a solarinverter or grid-tie inverter configured to convert the DC output fromPV field 302 into a sinusoidal AC output synchronized to the gridfrequency of energy grid 312. In some embodiments, power inverter 304receives a cumulative DC output from PV field 302. For example, powerinverter 304 may be a string inverter or a central inverter. In otherembodiments, power inverter 304 may include a collection ofmicro-inverters connected to each solar panel or solar cell. PV fieldpower inverter 304 may convert the DC power output P_(PV) into an ACpower output u_(PV) and provide the AC power output u_(PV) to POI 310.

Power inverter 304 may receive the DC power output P_(PV) from PV field302 and convert the DC power output to an AC power output that can befed into energy grid 312. Power inverter 304 may synchronize thefrequency of the AC power output with that of energy grid 312 (e.g., 50Hz or 60 Hz) using a local oscillator and may limit the voltage of theAC power output to no higher than the grid voltage. In some embodiments,power inverter 304 is a resonant inverter that includes or uses LCcircuits to remove the harmonics from a simple square wave in order toachieve a sine wave matching the frequency of energy grid 312. Invarious embodiments, power inverter 304 may operate using high-frequencytransformers, low-frequency transformers, or without transformers.Low-frequency transformers may convert the DC output from PV field 302directly to the AC output provided to energy grid 312. High-frequencytransformers may employ a multi-step process that involves convertingthe DC output to high-frequency AC, then back to DC, and then finally tothe AC output provided to energy grid 312.

Power inverter 304 may be configured to perform maximum power pointtracking and/or anti-islanding. Maximum power point tracking may allowpower inverter 304 to produce the maximum possible AC power from PVfield 302. For example, power inverter 304 may sample the DC poweroutput from PV field 302 and apply a variable resistance to find theoptimum maximum power point. Anti-islanding is a protection mechanismthat immediately shuts down power inverter 304 (i.e., preventing powerinverter 304 from generating AC power) when the connection to anelectricity-consuming load no longer exists. In some embodiments, PVfield power inverter 304 performs ramp rate control by limiting thepower generated by PV field 302.

Still referring to FIG. 3, system 300 is shown to include a batterypower inverter 308. Battery power inverter 308 may be configured to drawa DC power P_(bat) from battery 306, convert the DC power P_(bat) intoan AC power u_(bat), and provide the AC power u_(bat) to POI 310.Battery power inverter 308 may also be configured to draw the AC poweru_(bat) from POI 310, convert the AC power u_(bat) into a DC batterypower P_(bat), and store the DC battery power P_(bat) in battery 306.The DC battery power P_(bat) may be positive if battery 306 is providingpower to battery power inverter 308 (i.e., if battery 306 isdischarging) or negative if battery 306 is receiving power from batterypower inverter 308 (i.e., if battery 306 is charging). Similarly, the ACbattery power u_(bat) may be positive if battery power inverter 308 isproviding power to POI 310 or negative if battery power inverter 308 isreceiving power from POI 310.

The AC battery power u_(bat) is shown to include an amount of power usedfor frequency regulation (i.e., u_(FR)) and an amount of power used forramp rate control (i.e., u_(RR)) which together form the AC batterypower (i.e., u_(bat)=u_(FR)+u_(RR)). The DC battery power P_(bat) isshown to include both u_(FR) and u_(RR) as well as an additional termP_(loss) representing power losses in battery 306 and/or battery powerinverter 308 (i.e., P_(bat)=u_(FR)+u_(RR)+P_(loss)). The PV field poweru_(PV) and the battery power u_(bat) combine at POI 110 to form P_(POI)(i.e., P_(POI)=u_(PV)+u_(bat)), which represents the amount of powerprovided to energy grid 312. P_(POI) may be positive if POI 310 isproviding power to energy grid 312 or negative if POI 310 is receivingpower from energy grid 312.

Still referring to FIG. 3, system 300 is shown to include a controller314. Controller 314 may be configured to generate a PV power setpointu_(PV) for PV field power inverter 304 and a battery power setpointu_(bat) for battery power inverter 308. Throughout this disclosure, thevariable u_(PV) is used to refer to both the PV power setpoint generatedby controller 314 and the AC power output of PV field power inverter 304since both quantities have the same value. Similarly, the variableu_(bat) is used to refer to both the battery power setpoint generated bycontroller 314 and the AC power output/input of battery power inverter308 since both quantities have the same value.

PV field power inverter 304 uses the PV power setpoint u_(PV) to controlan amount of the PV field power P_(PV) to provide to POI 110. Themagnitude of u_(PV) may be the same as the magnitude of P_(PV) or lessthan the magnitude of P_(PV). For example, u_(PV) may be the same asP_(PV) if controller 314 determines that PV field power inverter 304 isto provide all of the photovoltaic power P_(PV) to POI 310. However,u_(PV) may be less than P_(PV) if controller 314 determines that PVfield power inverter 304 is to provide less than all of the photovoltaicpower P_(PV) to POI 310. For example, controller 314 may determine thatit is desirable for PV field power inverter 304 to provide less than allof the photovoltaic power P_(PV) to POI 310 to prevent the ramp ratefrom being exceeded and/or to prevent the power at POI 310 fromexceeding a power limit.

Battery power inverter 308 uses the battery power setpoint u_(bat) tocontrol an amount of power charged or discharged by battery 306. Thebattery power setpoint u_(bat) may be positive if controller 314determines that battery power inverter 308 is to draw power from battery306 or negative if controller 314 determines that battery power inverter308 is to store power in battery 306. The magnitude of u_(bat) controlsthe rate at which energy is charged or discharged by battery 306.

Controller 314 may generate u_(PV) and u_(bat) based on a variety ofdifferent variables including, for example, a power signal from PV field302 (e.g., current and previous values for P_(PV)), the currentstate-of-charge (SOC) of battery 306, a maximum battery power limit, amaximum power limit at POI 310, the ramp rate limit, the grid frequencyof energy grid 312, and/or other variables that can be used bycontroller 314 to perform ramp rate control and/or frequency regulation.Advantageously, controller 314 generates values for u_(PV) and u_(bat)that maintain the ramp rate of the PV power within the ramp ratecompliance limit while participating in the regulation of grid frequencyand maintaining the SOC of battery 306 within a predetermined desirablerange.

An exemplary controller which can be used as controller 314 andexemplary processes which may be performed by controller 314 to generatethe PV power setpoint u_(PV) and the battery power setpoint u_(bat) aredescribed in detail in U.S. patent application Ser. No. 15/247,869 filedAug. 25, 2016, U.S. patent application Ser. No. 15/247,844 filed Aug.25, 2016, U.S. patent application Ser. No. 15/247,788 filed Aug. 25,2016, U.S. patent application Ser. No. 15/247,872 filed Aug. 25, 2016,U.S. patent application Ser. No. 15/247,880 filed Aug. 25, 2016, andU.S. patent application Ser. No. 15/247,873 filed Aug. 25, 2016. Theentire disclosure of each of these patent applications is incorporatedby reference herein.

Energy Storage System with Thermal and Electrical Energy Storage

Referring now to FIG. 5, a block diagram of an energy storage system 500is shown, according to an exemplary embodiment. Energy storage system500 is shown to include a building 502. Building 502 may be the same orsimilar to buildings 116, as described with reference to FIG. 1. Forexample, building 502 may be equipped with a HVAC system and/or abuilding management system that operates to control conditions withinbuilding 502. In some embodiments, building 502 includes multiplebuildings (i.e., a campus) served by energy storage system 500. Building502 may demand various resources including, for example, hot thermalenergy (e.g., hot water), cold thermal energy (e.g., cold water), and/orelectrical energy. The resources may be demanded by equipment orsubsystems within building 502 or by external systems that provideservices for building 502 (e.g., heating, cooling, air circulation,lighting, electricity, etc.). Energy storage system 500 operates tosatisfy the resource demand associated with building 502.

Energy storage system 500 is shown to include a plurality of utilities510. Utilities 510 may provide energy storage system 500 with resourcessuch as electricity, water, natural gas, or any other resource that canbe used by energy storage system 500 to satisfy the demand of building502. For example, utilities 510 are shown to include an electric utility511, a water utility 512, a natural gas utility 513, and utility M 514,where M is the total number of utilities 510. In some embodiments,utilities 510 are commodity suppliers from which resources and othertypes of commodities can be purchased. Resources purchased fromutilities 510 can be used by generator subplants 520 to producegenerated resources (e.g., hot water, cold water, electricity, steam,etc.), stored in storage subplants 530 for later use, or provideddirectly to building 502. For example, utilities 510 are shown providingelectricity directly to building 502 and storage subplants 530.

Energy storage system 500 is shown to include a plurality of generatorsubplants 520. In some embodiments, generator subplants 520 arecomponents of a central plant (e.g., central plant 118). Generatorsubplants 520 are shown to include a heater subplant 521, a chillersubplant 522, a heat recovery chiller subplant 523, a steam subplant524, an electricity subplant 525, and subplant N, where N is the totalnumber of generator subplants 520. Generator subplants 520 may beconfigured to convert one or more input resources into one or moreoutput resources by operation of the equipment within generatorsubplants 520. For example, heater subplant 521 may be configured togenerate hot thermal energy (e.g., hot water) by heating water usingelectricity or natural gas. Chiller subplant 522 may be configured togenerate cold thermal energy (e.g., cold water) by chilling water usingelectricity. Heat recovery chiller subplant 523 may be configured togenerate hot thermal energy and cold thermal energy by removing heatfrom one water supply and adding the heat to another water supply. Steamsubplant 524 may be configured to generate steam by boiling water usingelectricity or natural gas. Electricity subplant 525 may be configuredto generate electricity using mechanical generators (e.g., a steamturbine, a gas-powered generator, etc.) or other types ofelectricity-generating equipment (e.g., photovoltaic equipment,hydroelectric equipment, etc.).

The input resources used by generator subplants 520 may be provided byutilities 510, retrieved from storage subplants 530, and/or generated byother generator subplants 520. For example, steam subplant 524 mayproduce steam as an output resource. Electricity subplant 525 mayinclude a steam turbine that uses the steam generated by steam subplant524 as an input resource to generate electricity. The output resourcesproduced by generator subplants 520 may be stored in storage subplants530, provided to building 502, sold to energy purchasers 504, and/orused by other generator subplants 520. For example, the electricitygenerated by electricity subplant 525 may be stored in electrical energystorage 533, used by chiller subplant 522 to generate cold thermalenergy, provided to building 502, and/or sold to energy purchasers 504.

Energy storage system 500 is shown to include storage subplants 530. Insome embodiments, storage subplants 530 are components of a centralplant (e.g., central plant 118). Storage subplants 530 may be configuredto store energy and other types of resources for later use. Each ofstorage subplants 530 may be configured to store a different type ofresource. For example, storage subplants 530 are shown to include hotthermal energy storage 531 (e.g., one or more hot water storage tanks),cold thermal energy storage 532 (e.g., one or more cold thermal energystorage tanks), electrical energy storage 533 (e.g., one or morebatteries), and resource type P storage 534, where P is the total numberof storage subplants 530. The resources stored in subplants 530 may bepurchased directly from utilities 510 or generated by generatorsubplants 520.

In some embodiments, storage subplants 530 are used by energy storagesystem 500 to take advantage of price-based demand response (PBDR)programs. PBDR programs encourage consumers to reduce consumption whengeneration, transmission, and distribution costs are high. PBDR programsare typically implemented (e.g., by utilities 510) in the form of energyprices that vary as a function of time. For example, utilities 510 mayincrease the price per unit of electricity during peak usage hours toencourage customers to reduce electricity consumption during peak times.Some utilities also charge consumers a separate demand charge based onthe maximum rate of electricity consumption at any time during apredetermined demand charge period.

Advantageously, storing energy and other types of resources in subplants530 allows for the resources to be purchased at times when the resourcesare relatively less expensive (e.g., during non-peak electricity hours)and stored for use at times when the resources are relatively moreexpensive (e.g., during peak electricity hours). Storing resources insubplants 530 also allows the resource demand of building 502 to beshifted in time. For example, resources can be purchased from utilities510 at times when the demand for heating or cooling is low andimmediately converted into hot or cold thermal energy by generatorsubplants 520. The thermal energy can be stored in storage subplants 530and retrieved at times when the demand for heating or cooling is high.This allows energy storage system 500 to smooth the resource demand ofbuilding 502 and reduces the maximum required capacity of generatorsubplants 520. Smoothing the demand also allows energy storage system500 to reduce the peak electricity consumption, which results in a lowerdemand charge.

In some embodiments, storage subplants 530 are used by energy storagesystem 500 to take advantage of incentive-based demand response (IBDR)programs. IBDR programs provide incentives to customers who have thecapability to store energy, generate energy, or curtail energy usageupon request. Incentives are typically provided in the form of monetaryrevenue paid by utilities 510 or by an independent system operator(ISO). IBDR programs supplement traditional utility-owned generation,transmission, and distribution assets with additional options formodifying demand load curves. For example, stored energy can be sold toenergy purchasers 504 (e.g., an energy grid) to supplement the energygenerated by utilities 510. In some instances, incentives forparticipating in an IBDR program vary based on how quickly a system canrespond to a request to change power output/consumption. Fasterresponses may be compensated at a higher level. Advantageously,electrical energy storage 533 allows system 500 to quickly respond to arequest for electric power by rapidly discharging stored electricalenergy to energy purchasers 504.

Still referring to FIG. 5, energy storage system 500 is shown to includean energy storage controller 506. Energy storage controller 506 may beconfigured to control the distribution, production, storage, and usageof resources in energy storage system 500. In some embodiments, energystorage controller 506 performs an optimization process determine anoptimal set of control decisions for each time step within anoptimization period. The control decisions may include, for example, anoptimal amount of each resource to purchase from utilities 510, anoptimal amount of each resource to produce or convert using generatorsubplants 520, an optimal amount of each resource to store or removefrom storage subplants 530, an optimal amount of each resource to sellto energy purchasers 504, and/or an optimal amount of each resource toprovide to building 502. In some embodiments, the control decisionsinclude an optimal amount of each input resource and output resource foreach of generator subplants 520.

Controller 506 may be configured to maximize the economic value ofoperating energy storage system 500 over the duration of theoptimization period. The economic value may be defined by a valuefunction that expresses economic value as a function of the controldecisions made by controller 506. The value function may account for thecost of resources purchased from utilities 510, revenue generated byselling resources to energy purchasers 504, and the cost of operatingenergy storage system 500. In some embodiments, the cost of operatingenergy storage system 500 includes a cost for losses in battery capacityas a result of the charging and discharging electrical energy storage533. The cost of operating energy storage system 500 may also include acost of excessive equipment start/stops during the optimization period.

Each of subplants 520-530 may include equipment that can be controlledby energy storage controller 506 to optimize the performance of energystorage system 500. Subplant equipment may include, for example, heatingdevices, chillers, heat recovery heat exchangers, cooling towers, energystorage devices, pumps, valves, and/or other devices of subplants520-530. Individual devices of generator subplants 520 can be turned onor off to adjust the resource production of each generator subplant. Insome embodiments, individual devices of generator subplants 520 can beoperated at variable capacities (e.g., operating a chiller at 10%capacity or 60% capacity) according to an operating setpoint receivedfrom energy storage controller 506.

In some embodiments, one or more of subplants 520-530 includes asubplant level controller configured to control the equipment of thecorresponding subplant. For example, energy storage controller 506 maydetermine an on/off configuration and global operating setpoints for thesubplant equipment. In response to the on/off configuration and receivedglobal operating setpoints, the subplant controllers may turn individualdevices of their respective equipment on or off, and implement specificoperating setpoints (e.g., damper position, vane position, fan speed,pump speed, etc.) to reach or maintain the global operating setpoints.

In some embodiments, controller 506 maximizes the life cycle economicvalue of energy storage system 500 while participating in PBDR programs,IBDR programs, or simultaneously in both PBDR and IBDR programs. For theIBDR programs, controller 506 may use statistical estimates of pastclearing prices, mileage ratios, and event probabilities to determinethe revenue generation potential of selling stored energy to energypurchasers 504. For the PBDR programs, controller 506 may usepredictions of ambient conditions, facility thermal loads, andthermodynamic models of installed equipment to estimate the resourceconsumption of subplants 520. Controller 506 may use predictions of theresource consumption to monetize the costs of running the equipment.

Controller 506 may automatically determine (e.g., without humanintervention) a combination of PBDR and/or IBDR programs in which toparticipate over the optimization period in order to maximize economicvalue. For example, controller 506 may consider the revenue generationpotential of IBDR programs, the cost reduction potential of PBDRprograms, and the equipment maintenance/replacement costs that wouldresult from participating in various combinations of the IBDR programsand PBDR programs. Controller 506 may weigh the benefits ofparticipation against the costs of participation to determine an optimalcombination of programs in which to participate. Advantageously, thisallows controller 506 to determine an optimal set of control decisionsthat maximize the overall value of operating energy storage system 500.

In some instances, controller 506 may determine that it would bebeneficial to participate in an IBDR program when the revenue generationpotential is high and/or the costs of participating are low. Forexample, controller 506 may receive notice of a synchronous reserveevent from an IBDR program which requires energy storage system 500 toshed a predetermined amount of power. Controller 506 may determine thatit is optimal to participate in the IBDR program if cold thermal energystorage 532 has enough capacity to provide cooling for building 502while the load on chiller subplant 522 is reduced in order to shed thepredetermined amount of power.

In other instances, controller 506 may determine that it would not bebeneficial to participate in an IBDR program when the resources requiredto participate are better allocated elsewhere. For example, if building502 is close to setting a new peak demand that would greatly increasethe PBDR costs, controller 506 may determine that only a small portionof the electrical energy stored in electrical energy storage 533 will besold to energy purchasers 504 in order to participate in a frequencyresponse market. Controller 506 may determine that the remainder of theelectrical energy will be used to power chiller subplant 522 to preventa new peak demand from being set.

In some embodiments, energy storage system 500 and controller includesome or all of the components and/or features described in U.S. patentapplication Ser. No. 15/247,875 filed Aug. 25, 2016, U.S. patentapplication Ser. No. 15/247,879 filed Aug. 25, 2016, and U.S. patentapplication Ser. No. 15/247,881 filed Aug. 25, 2016. The entiredisclosure of each of these patent applications is incorporated byreference herein.

Energy Storage Controller

Referring now to FIG. 6, a block diagram illustrating energy storagecontroller 506 in greater detail is shown, according to an exemplaryembodiment. Energy storage controller 506 is shown providing controldecisions to a building management system (BMS) 606. In someembodiments, BMS 606 is the same or similar the BMS described withreference to FIG. 1. The control decisions provided to BMS 606 mayinclude resource purchase amounts for utilities 510, setpoints forgenerator subplants 520, and/or charge/discharge rates for storagesubplants 530.

BMS 606 may be configured to monitor conditions within a controlledbuilding or building zone. For example, BMS 606 may receive input fromvarious sensors (e.g., temperature sensors, humidity sensors, airflowsensors, voltage sensors, etc.) distributed throughout the building andmay report building conditions to energy storage controller 506.Building conditions may include, for example, a temperature of thebuilding or a zone of the building, a power consumption (e.g., electricload) of the building, a state of one or more actuators configured toaffect a controlled state within the building, or other types ofinformation relating to the controlled building. BMS 606 may operatesubplants 520-530 to affect the monitored conditions within the buildingand to serve the thermal energy loads of the building.

BMS 606 may receive control signals from energy storage controller 506specifying on/off states, charge/discharge rates, and/or setpoints forthe subplant equipment. BMS 606 may control the equipment (e.g., viaactuators, power relays, etc.) in accordance with the control signalsprovided by energy storage controller 506. For example, BMS 606 mayoperate the equipment using closed loop control to achieve the setpointsspecified by energy storage controller 506. In various embodiments, BMS606 may be combined with energy storage controller 506 or may be part ofa separate building management system. According to an exemplaryembodiment, BMS 606 is a METASYS® brand building management system, assold by Johnson Controls, Inc.

Energy storage controller 506 may monitor the status of the controlledbuilding using information received from BMS 606. Energy storagecontroller 506 may be configured to predict the thermal energy loads(e.g., heating loads, cooling loads, etc.) of the building for pluralityof time steps in an optimization period (e.g., using weather forecastsfrom a weather service 604). Energy storage controller 506 may alsopredict the revenue generation potential of IBDR programs using anincentive event history (e.g., past clearing prices, mileage ratios,event probabilities, etc.) from incentive programs 602. Energy storagecontroller 506 may generate control decisions that optimize the economicvalue of operating energy storage system 500 over the duration of theoptimization period subject to constraints on the optimization process(e.g., energy balance constraints, load satisfaction constraints, etc.).The optimization process performed by energy storage controller 506 isdescribed in greater detail below.

According to an exemplary embodiment, energy storage controller 506 isintegrated within a single computer (e.g., one server, one housing,etc.). In various other exemplary embodiments, energy storage controller506 can be distributed across multiple servers or computers (e.g., thatcan exist in distributed locations). In another exemplary embodiment,energy storage controller 506 may integrated with a smart buildingmanager that manages multiple building systems and/or combined with BMS606.

Energy storage controller 506 is shown to include a communicationsinterface 636 and a processing circuit 607. Communications interface 636may include wired or wireless interfaces (e.g., jacks, antennas,transmitters, receivers, transceivers, wire terminals, etc.) forconducting data communications with various systems, devices, ornetworks. For example, communications interface 636 may include anEthernet card and port for sending and receiving data via anEthernet-based communications network and/or a WiFi transceiver forcommunicating via a wireless communications network. Communicationsinterface 636 may be configured to communicate via local area networksor wide area networks (e.g., the Internet, a building WAN, etc.) and mayuse a variety of communications protocols (e.g., BACnet, IP, LON, etc.).

Communications interface 636 may be a network interface configured tofacilitate electronic data communications between energy storagecontroller 506 and various external systems or devices (e.g., BMS 606,subplants 520-530, utilities 510, etc.). For example, energy storagecontroller 506 may receive information from BMS 606 indicating one ormore measured states of the controlled building (e.g., temperature,humidity, electric loads, etc.) and one or more states of subplants520-530 (e.g., equipment status, power consumption, equipmentavailability, etc.). Communications interface 636 may receive inputsfrom BMS 606 and/or subplants 520-530 and may provide operatingparameters (e.g., on/off decisions, setpoints, etc.) to subplants520-530 via BMS 606. The operating parameters may cause subplants520-530 to activate, deactivate, or adjust a setpoint for variousdevices thereof.

Still referring to FIG. 6, processing circuit 607 is shown to include aprocessor 608 and memory 610. Processor 608 may be a general purpose orspecific purpose processor, an application specific integrated circuit(ASIC), one or more field programmable gate arrays (FPGAs), a group ofprocessing components, or other suitable processing components.Processor 608 may be configured to execute computer code or instructionsstored in memory 610 or received from other computer readable media(e.g., CDROM, network storage, a remote server, etc.).

Memory 610 may include one or more devices (e.g., memory units, memorydevices, storage devices, etc.) for storing data and/or computer codefor completing and/or facilitating the various processes described inthe present disclosure. Memory 610 may include random access memory(RAM), read-only memory (ROM), hard drive storage, temporary storage,non-volatile memory, flash memory, optical memory, or any other suitablememory for storing software objects and/or computer instructions. Memory610 may include database components, object code components, scriptcomponents, or any other type of information structure for supportingthe various activities and information structures described in thepresent disclosure. Memory 610 may be communicably connected toprocessor 608 via processing circuit 607 and may include computer codefor executing (e.g., by processor 608) one or more processes describedherein.

Memory 610 is shown to include a building status monitor 624. Energystorage controller 506 may receive data regarding the overall buildingor building space to be heated or cooled by system 500 via buildingstatus monitor 624. In an exemplary embodiment, building status monitor624 may include a graphical user interface component configured toprovide graphical user interfaces to a user for selecting buildingrequirements (e.g., overall temperature parameters, selecting schedulesfor the building, selecting different temperature levels for differentbuilding zones, etc.).

Energy storage controller 506 may determine on/off configurations andoperating setpoints to satisfy the building requirements received frombuilding status monitor 624. In some embodiments, building statusmonitor 624 receives, collects, stores, and/or transmits cooling loadrequirements, building temperature setpoints, occupancy data, weatherdata, energy data, schedule data, and other building parameters. In someembodiments, building status monitor 624 stores data regarding energycosts, such as pricing information available from utilities 510 (energycharge, demand charge, etc.).

Still referring to FIG. 6, memory 610 is shown to include a load/ratepredictor 622. Load/rate predictor 622 may be configured to predict thethermal energy loads (

_(k)) of the building or campus for each time step k (e.g., k=1 . . . n)of an optimization period. Load/rate predictor 622 is shown receivingweather forecasts from a weather service 604. In some embodiments,load/rate predictor 622 predicts the thermal energy loads

_(k) as a function of the weather forecasts. In some embodiments,load/rate predictor 622 uses feedback from BMS 606 to predict loads

_(k). Feedback from BMS 606 may include various types of sensory inputs(e.g., temperature, flow, humidity, enthalpy, etc.) or other datarelating to the controlled building (e.g., inputs from a HVAC system, alighting control system, a security system, a water system, etc.).

In some embodiments, load/rate predictor 622 receives a measuredelectric load and/or previous measured load data from BMS 606 (e.g., viabuilding status monitor 624). Load/rate predictor 622 may predict loads

_(k) as a function of a given weather forecast ({circumflex over(ϕ)}_(w)), a day type (day), the time of day (t), and previous measuredload data (Y_(k-1)). Such a relationship is expressed in the followingequation:

_(k)=ƒ({circumflex over (ϕ)}_(w),day,t|Y _(k-1))

In some embodiments, load/rate predictor 622 uses a deterministic plusstochastic model trained from historical load data to predict loads

_(k). Load/rate predictor 622 may use any of a variety of predictionmethods to predict loads

_(k) (e.g., linear regression for the deterministic portion and an ARmodel for the stochastic portion). Load/rate predictor 622 may predictone or more different types of loads for the building or campus. Forexample, load/rate predictor 622 may predict a hot water load

_(Hot,k) and a cold water load

_(Cold,k) for each time step k within the prediction window. In someembodiments, load/rate predictor 622 makes load/rate predictions usingthe techniques described in U.S. patent application Ser. No. 14/717,593.

Load/rate predictor 622 is shown receiving utility rates from utilities510. Utility rates may indicate a cost or price per unit of a resource(e.g., electricity, natural gas, water, etc.) provided by utilities 510at each time step k in the prediction window. In some embodiments, theutility rates are time-variable rates. For example, the price ofelectricity may be higher at certain times of day or days of the week(e.g., during high demand periods) and lower at other times of day ordays of the week (e.g., during low demand periods). The utility ratesmay define various time periods and a cost per unit of a resource duringeach time period. Utility rates may be actual rates received fromutilities 510 or predicted utility rates estimated by load/ratepredictor 622.

In some embodiments, the utility rates include demand charges for one ormore resources provided by utilities 510. A demand charge may define aseparate cost imposed by utilities 510 based on the maximum usage of aparticular resource (e.g., maximum energy consumption) during a demandcharge period. The utility rates may define various demand chargeperiods and one or more demand charges associated with each demandcharge period. In some instances, demand charge periods may overlappartially or completely with each other and/or with the predictionwindow. Advantageously, demand response optimizer 630 may be configuredto account for demand charges in the high level optimization processperformed by high level optimizer 632. Utilities 510 may be defined bytime-variable (e.g., hourly) prices, a maximum service level (e.g., amaximum rate of consumption allowed by the physical infrastructure or bycontract) and, in the case of electricity, a demand charge or a chargefor the peak rate of consumption within a certain period. Load/ratepredictor 622 may store the predicted loads

_(k) and the utility rates in memory 610 and/or provide the predictedloads

_(k) and the utility rates to demand response optimizer 630.

Still referring to FIG. 6, memory 610 is shown to include an incentiveestimator 620. Incentive estimator 620 may be configured to estimate therevenue generation potential of participating in various incentive-baseddemand response (IBDR) programs. In some embodiments, incentiveestimator 620 receives an incentive event history from incentiveprograms 602. The incentive event history may include a history of pastIBDR events from incentive programs 602. An IBDR event may include aninvitation from incentive programs 602 to participate in an IBDR programin exchange for a monetary incentive. The incentive event history mayindicate the times at which the past IBDR events occurred and attributesdescribing the IBDR events (e.g., clearing prices, mileage ratios,participation requirements, etc.). Incentive estimator 620 may use theincentive event history to estimate IBDR event probabilities during theoptimization period.

Incentive estimator 620 is shown providing incentive predictions todemand response optimizer 630. The incentive predictions may include theestimated IBDR probabilities, estimated participation requirements, anestimated amount of revenue from participating in the estimated IBDRevents, and/or any other attributes of the predicted IBDR events. Demandresponse optimizer 630 may use the incentive predictions along with thepredicted loads

_(k) and utility rates from load/rate predictor 622 to determine anoptimal set of control decisions for each time step within theoptimization period.

Still referring to FIG. 6, memory 610 is shown to include a demandresponse optimizer 630. Demand response optimizer 630 may perform acascaded optimization process to optimize the performance of energystorage system 500. For example, demand response optimizer 630 is shownto include a high level optimizer 632 and a low level optimizer 634.High level optimizer 632 may control an outer (e.g., subplant level)loop of the cascaded optimization. High level optimizer 632 maydetermine an optimal set of control decisions for each time step in theprediction window in order to optimize (e.g., maximize) the value ofoperating energy storage system 500. Control decisions made by highlevel optimizer 632 may include, for example, load setpoints for each ofgenerator subplants 520, charge/discharge rates for each of storagesubplants 530, resource purchase amounts for each type of resourcepurchased from utilities 510, and/or an amount of each resource sold toenergy purchasers 504. In other words, the control decisions may defineresource allocation at each time step. The control decisions made byhigh level optimizer 632 are based on the statistical estimates ofincentive event probabilities and revenue generation potential forvarious IBDR events as well as the load and rate predictions.

Low level optimizer 634 may control an inner (e.g., equipment level)loop of the cascaded optimization. Low level optimizer 634 may determinehow to best run each subplant at the load setpoint determined by highlevel optimizer 632. For example, low level optimizer 634 may determineon/off states and/or operating setpoints for various devices of thesubplant equipment in order to optimize (e.g., minimize) the energyconsumption of each subplant while meeting the resource allocationsetpoint for the subplant. In some embodiments, low level optimizer 634receives actual incentive events from incentive programs 602. Low leveloptimizer 634 may determine whether to participate in the incentiveevents based on the resource allocation set by high level optimizer 632.For example, if insufficient resources have been allocated to aparticular IBDR program by high level optimizer 632 or if the allocatedresources have already been used, low level optimizer 634 may determinethat energy storage system 500 will not participate in the IBDR programand may ignore the IBDR event. However, if the required resources havebeen allocated to the IBDR program and are available in storagesubplants 530, low level optimizer 634 may determine that system 500will participate in the IBDR program in response to the IBDR event. Thecascaded optimization process performed by demand response optimizer 630is described in greater detail in U.S. patent application Ser. No.15/247,885.

Still referring to FIG. 6, memory 610 is shown to include a subplantcontrol module 628. Subplant control module 628 may store historicaldata regarding past operating statuses, past operating setpoints, andinstructions for calculating and/or implementing control parameters forsubplants 520-530. Subplant control module 628 may also receive, store,and/or transmit data regarding the conditions of individual devices ofthe subplant equipment, such as operating efficiency, equipmentdegradation, a date since last service, a lifespan parameter, acondition grade, or other device-specific data. Subplant control module628 may receive data from subplants 520-530 and/or BMS 606 viacommunications interface 636. Subplant control module 628 may alsoreceive and store on/off statuses and operating setpoints from low leveloptimizer 634.

Data and processing results from demand response optimizer 630, subplantcontrol module 628, or other modules of energy storage controller 506may be accessed by (or pushed to) monitoring and reporting applications626. Monitoring and reporting applications 626 may be configured togenerate real time “system health” dashboards that can be viewed andnavigated by a user (e.g., a system engineer). For example, monitoringand reporting applications 626 may include a web-based monitoringapplication with several graphical user interface (GUI) elements (e.g.,widgets, dashboard controls, windows, etc.) for displaying keyperformance indicators (KPI) or other information to users of a GUI. Inaddition, the GUI elements may summarize relative energy use andintensity across energy storage systems in different buildings (real ormodeled), different campuses, or the like. Other GUI elements or reportsmay be generated and shown based on available data that allow users toassess performance across one or more energy storage systems from onescreen. The user interface or report (or underlying data engine) may beconfigured to aggregate and categorize operating conditions by building,building type, equipment type, and the like. The GUI elements mayinclude charts or histograms that allow the user to visually analyze theoperating parameters and power consumption for the devices of the energystorage system.

Still referring to FIG. 6, energy storage controller 506 may include oneor more GUI servers, web services 612, or GUI engines 614 to supportmonitoring and reporting applications 626. In various embodiments,applications 626, web services 612, and GUI engine 614 may be providedas separate components outside of energy storage controller 506 (e.g.,as part of a smart building manager). Energy storage controller 506 maybe configured to maintain detailed historical databases (e.g.,relational databases, XML, databases, etc.) of relevant data andincludes computer code modules that continuously, frequently, orinfrequently query, aggregate, transform, search, or otherwise processthe data maintained in the detailed databases. Energy storage controller506 may be configured to provide the results of any such processing toother databases, tables, XML files, or other data structures for furtherquerying, calculation, or access by, for example, external monitoringand reporting applications.

Energy storage controller 506 is shown to include configuration tools616. Configuration tools 616 can allow a user to define (e.g., viagraphical user interfaces, via prompt-driven “wizards,” etc.) how energystorage controller 506 should react to changing conditions in the energystorage subsystems. In an exemplary embodiment, configuration tools 616allow a user to build and store condition-response scenarios that cancross multiple energy storage system devices, multiple building systems,and multiple enterprise control applications (e.g., work ordermanagement system applications, entity resource planning applications,etc.). For example, configuration tools 616 can provide the user withthe ability to combine data (e.g., from subsystems, from eventhistories) using a variety of conditional logic. In varying exemplaryembodiments, the conditional logic can range from simple logicaloperators between conditions (e.g., AND, OR, XOR, etc.) to pseudo-codeconstructs or complex programming language functions (allowing for morecomplex interactions, conditional statements, loops, etc.).Configuration tools 616 can present user interfaces for building suchconditional logic. The user interfaces may allow users to definepolicies and responses graphically. In some embodiments, the userinterfaces may allow a user to select a pre-stored or pre-constructedpolicy and adapt it or enable it for use with their system.

Planning Tool

Referring now to FIG. 7, a block diagram of a planning system 700 isshown, according to an exemplary embodiment. Planning system 700 may beconfigured to use demand response optimizer 630 as part of a planningtool 702 to simulate the operation of a central plant over apredetermined time period (e.g., a day, a month, a week, a year, etc.)for planning, budgeting, and/or design considerations. When implementedin planning tool 702, demand response optimizer 630 may operate in asimilar manner as described with reference to FIG. 6. For example,demand response optimizer 630 may use building loads and utility ratesto determine an optimal resource allocation to minimize cost over asimulation period. However, planning tool 702 may not be responsible forreal-time control of a building management system or central plant.

Planning tool 702 can be configured to determine the benefits ofinvesting in a battery asset and the financial metrics associated withthe investment. Such financial metrics can include, for example, theinternal rate of return (IRR), net present value (NPV), and/or simplepayback period (SPP). Planning tool 702 can also assist a user indetermining the size of the battery which yields optimal financialmetrics such as maximum NPV or a minimum SPP. In some embodiments,planning tool 702 allows a user to specify a battery size andautomatically determines the benefits of the battery asset fromparticipating in selected IBDR programs while performing PBDR, asdescribed with reference to FIG. 5. In some embodiments, planning tool702 is configured to determine the battery size that minimizes SPP giventhe IBDR programs selected and the requirement of performing PBDR. Insome embodiments, planning tool 702 is configured to determine thebattery size that maximizes NPV given the IBDR programs selected and therequirement of performing PBDR.

In planning tool 702, high level optimizer 632 may receive planned loadsand utility rates for the entire simulation period. The planned loadsand utility rates may be defined by input received from a user via aclient device 722 (e.g., user-defined, user selected, etc.) and/orretrieved from a plan information database 726. High level optimizer 632uses the planned loads and utility rates in conjunction with subplantcurves from low level optimizer 634 to determine an optimal resourceallocation (i.e., an optimal dispatch schedule) for a portion of thesimulation period.

The portion of the simulation period over which high level optimizer 632optimizes the resource allocation may be defined by a prediction windowending at a time horizon. With each iteration of the optimization, theprediction window is shifted forward and the portion of the dispatchschedule no longer in the prediction window is accepted (e.g., stored oroutput as results of the simulation). Load and rate predictions may bepredefined for the entire simulation and may not be subject toadjustments in each iteration. However, shifting the prediction windowforward in time may introduce additional plan information (e.g., plannedloads and/or utility rates) for the newly-added time slice at the end ofthe prediction window. The new plan information may not have asignificant effect on the optimal dispatch schedule since only a smallportion of the prediction window changes with each iteration.

In some embodiments, high level optimizer 632 requests all of thesubplant curves used in the simulation from low level optimizer 634 atthe beginning of the simulation. Since the planned loads andenvironmental conditions are known for the entire simulation period,high level optimizer 632 may retrieve all of the relevant subplantcurves at the beginning of the simulation. In some embodiments, lowlevel optimizer 634 generates functions that map subplant production toequipment level production and resource use when the subplant curves areprovided to high level optimizer 632. These subplant to equipmentfunctions may be used to calculate the individual equipment productionand resource use (e.g., in a post-processing module) based on theresults of the simulation.

Still referring to FIG. 7, planning tool 702 is shown to include acommunications interface 704 and a processing circuit 706.Communications interface 704 may include wired or wireless interfaces(e.g., jacks, antennas, transmitters, receivers, transceivers, wireterminals, etc.) for conducting data communications with varioussystems, devices, or networks. For example, communications interface 704may include an Ethernet card and port for sending and receiving data viaan Ethernet-based communications network and/or a WiFi transceiver forcommunicating via a wireless communications network. Communicationsinterface 704 may be configured to communicate via local area networksor wide area networks (e.g., the Internet, a building WAN, etc.) and mayuse a variety of communications protocols (e.g., BACnet, IP, LON, etc.).

Communications interface 704 may be a network interface configured tofacilitate electronic data communications between planning tool 702 andvarious external systems or devices (e.g., client device 722, resultsdatabase 728, plan information database 726, etc.). For example,planning tool 702 may receive planned loads and utility rates fromclient device 722 and/or plan information database 726 viacommunications interface 704. Planning tool 702 may use communicationsinterface 704 to output results of the simulation to client device 722and/or to store the results in results database 728.

Still referring to FIG. 7, processing circuit 706 is shown to include aprocessor 710 and memory 712. Processor 710 may be a general purpose orspecific purpose processor, an application specific integrated circuit(ASIC), one or more field programmable gate arrays (FPGAs), a group ofprocessing components, or other suitable processing components.Processor 710 may be configured to execute computer code or instructionsstored in memory 712 or received from other computer readable media(e.g., CDROM, network storage, a remote server, etc.).

Memory 712 may include one or more devices (e.g., memory units, memorydevices, storage devices, etc.) for storing data and/or computer codefor completing and/or facilitating the various processes described inthe present disclosure. Memory 712 may include random access memory(RAM), read-only memory (ROM), hard drive storage, temporary storage,non-volatile memory, flash memory, optical memory, or any other suitablememory for storing software objects and/or computer instructions. Memory712 may include database components, object code components, scriptcomponents, or any other type of information structure for supportingthe various activities and information structures described in thepresent disclosure. Memory 712 may be communicably connected toprocessor 710 via processing circuit 706 and may include computer codefor executing (e.g., by processor 710) one or more processes describedherein.

Still referring to FIG. 7, memory 712 is shown to include a GUI engine716, web services 714, and configuration tools 718. In an exemplaryembodiment, GUI engine 716 includes a graphical user interface componentconfigured to provide graphical user interfaces to a user for selectingor defining plan information for the simulation (e.g., planned loads,utility rates, environmental conditions, etc.). Web services 714 mayallow a user to interact with planning tool 702 via a web portal and/orfrom a remote system or device (e.g., an enterprise controlapplication).

Configuration tools 718 can allow a user to define (e.g., via graphicaluser interfaces, via prompt-driven “wizards,” etc.) various parametersof the simulation such as the number and type of subplants, the deviceswithin each subplant, the subplant curves, device-specific efficiencycurves, the duration of the simulation, the duration of the predictionwindow, the duration of each time step, and/or various other types ofplan information related to the simulation. Configuration tools 718 canpresent user interfaces for building the simulation. The user interfacesmay allow users to define simulation parameters graphically. In someembodiments, the user interfaces allow a user to select a pre-stored orpre-constructed simulated plant and/or plan information (e.g., from planinformation database 726) and adapt it or enable it for use in thesimulation.

Still referring to FIG. 7, memory 712 is shown to include demandresponse optimizer 630. Demand response optimizer 630 may use theplanned loads and utility rates to determine an optimal resourceallocation over a prediction window. The operation of demand responseoptimizer 630 may be the same or similar as previously described withreference to FIGS. 6-8. With each iteration of the optimization process,demand response optimizer 630 may shift the prediction window forwardand apply the optimal resource allocation for the portion of thesimulation period no longer in the prediction window. Demand responseoptimizer 630 may use the new plan information at the end of theprediction window to perform the next iteration of the optimizationprocess. Demand response optimizer 630 may output the applied resourceallocation to reporting applications 730 for presentation to a clientdevice 722 (e.g., via user interface 724) or storage in results database728.

Still referring to FIG. 7, memory 712 is shown to include reportingapplications 730. Reporting applications 730 may receive the optimizedresource allocations from demand response optimizer 630 and, in someembodiments, costs associated with the optimized resource allocations.Reporting applications 730 may include a web-based reporting applicationwith several graphical user interface (GUI) elements (e.g., widgets,dashboard controls, windows, etc.) for displaying key performanceindicators (KPI) or other information to users of a GUI. In addition,the GUI elements may summarize relative energy use and intensity acrossvarious plants, subplants, or the like. Other GUI elements or reportsmay be generated and shown based on available data that allow users toassess the results of the simulation. The user interface or report (orunderlying data engine) may be configured to aggregate and categorizeresource allocation and the costs associated therewith and provide theresults to a user via a GUI. The GUI elements may include charts orhistograms that allow the user to visually analyze the results of thesimulation. An exemplary output that may be generated by reportingapplications 730 is shown in FIG. 8.

Referring now to FIG. 8, several graphs 800 illustrating the operationof planning tool 702 are shown, according to an exemplary embodiment.With each iteration of the optimization process, planning tool 702selects an optimization period (i.e., a portion of the simulationperiod) over which the optimization is performed. For example, planningtool 702 may select optimization period 802 for use in the firstiteration. Once the optimal resource allocation 810 has been determined,planning tool 702 may select a portion 818 of resource allocation 810 tosend to plant dispatch 830. Portion 818 may be the first b time steps ofresource allocation 810. Planning tool 702 may shift the optimizationperiod 802 forward in time, resulting in optimization period 804. Theamount by which the prediction window is shifted may correspond to theduration of time steps b.

Planning tool 702 may repeat the optimization process for optimizationperiod 804 to determine the optimal resource allocation 812. Planningtool 702 may select a portion 820 of resource allocation 812 to send toplant dispatch 830. Portion 820 may be the first b time steps ofresource allocation 812. Planning tool 702 may then shift the predictionwindow forward in time, resulting in optimization period 806. Thisprocess may be repeated for each subsequent optimization period (e.g.,optimization periods 806, 808, etc.) to generate updated resourceallocations (e.g., resource allocations 814, 816, etc.) and to selectportions of each resource allocation (e.g., portions 822, 824) to sendto plant dispatch 830. Plant dispatch 830 includes the first b timesteps 818-824 from each of optimization periods 802-808. Once theoptimal resource allocation is compiled for the entire simulationperiod, the results may be sent to reporting applications 730, resultsdatabase 728, and/or client device 722, as described with reference toFIG. 7.

Block-and-Index Rate Structure

Referring now to FIGS. 9-10, graphical representations of ablock-and-index rate structure are shown, according to exemplaryembodiments. Several pricing schemes (rate structures) for power (e.g.,electricity) and energy (e.g., natural gas) are used by various utilityproviders and various customers. As described in detail below, systemsand methods for cost optimization in building system and central energyfacilities may be adjusted to account for various pricing schemes.

One type of rate structure is known as a block-and-index rate structure,which provides some degree of hedging and risk management for a customerby allowing the customer to purchase a “block” of energy or power at afixed price, while paying for consumption beyond that block at thehourly market rate. FIGS. 9-10 illustrate a block-and-index ratestructure. FIG. 9 shows a graph 900 of a block-and-index rate structureduring a weekday, while FIG. 10 shows a graph 1000 of a block-and-indexrate structure during a weekend. Graph 900 and graph 1000 both include aload line 902 that plots the electric load of a building or centralenergy facility (plant) over time. In the example shown, the load line902 increases during daytime hours (e.g., during a typical workday),indicating increased electricity consumption during awake/working hoursand/or during warmer hours when a cooling load for a building may behigher.

Graph 900 and graph 1000 also show a first block 904. The first block904 represents a first pre-purchased, fixed rate block of power of afixed size. The first block 904 illustrates that at each time step thecustomer purchases a constant, fixed amount of power from the utilitycompany. Graph 900 also includes a second block 906. The second block906 represents a second pre-purchased, fixed rate block of power at afixed size. The second block 906 may be purchased at the same rate(price) or a different rate than the first block 904. The second block906 is included during peak load hours and illustrates that the customermay pre-purchase more power at some times of the day and less power atother times of the day.

In the notation used herein, energy or power e_(b,i) is pre-purchased ina block of size B at fixed block rate r_(b). The difference between theload line 902 and the top of the first block 904 or the second block 906at a time step i is the amount of energy e_(ind,i) purchased at thehourly day-ahead-pricing rate r_(DAP,i). The total energy or powerreceived from the utility provider (i.e., shown by the load line 902) isdenoted as e_(import,i). Accordingly, e_(import,i)=e_(b)+e_(ind,i) Insome cases, the total energy received from the utility provider may beless than the block size (i.e., e_(import,i)<B). In some such cases, thecustomer may be allowed to sell back the difference (i.e., e_(ind,i)<0)to the utility provider. In other such cases, the customer bears therisk of consuming less than the block size and may not sell back thedifference.

The block-and-index pricing scheme illustrated by FIGS. 9-10 may beapplied either to purchase of power (e.g., electricity in kilowatts) orenergy (e.g., natural gas or other resource in kWh). Power may bepurchased as a certain amount (i.e., a certain block size) at each timestep within an optimization period (e.g., each hour in a month asrepresented in FIGS. 9-10). Energy may be purchased as an amount ofenergy for a given period (e.g., one month), in which case the totalamount B is divided by the number of time steps to get a block size foreach time step. The optimization approaches described in detail belowproceed under these definitions.

Load-Following-Block Rate Structure

Referring now to FIG. 11, a graphical representation of aload-following-block rate structure is shown, according to an exemplaryembodiment. FIG. 11 shows a graph 1100. The graph 1100 includes the loadline 902 that plots total power e_(import,i) imported from the utilityprovider over time. The graph 1100 also shows a load-following block1102 for each time step. The load-following block 1102 represents anamount of power purchased at a fixed, pre-set rate. In theload-following-block rate structure of FIG. 11, the size of the block1102 is determined as a fixed hedging percentage α_(h) of the totalimported power e_(import,i), i.e., such that an amount of powerα_(h)*e_(import,i) is purchased at a fixed load-following-block rater_(LFB). This allows a customer to hedge on the price of power withoutcommitting to a fixed amount of power. The remainder of the importedpower (i.e., (1−α_(h))*e_(import,i)) is purchased at the hourly marketrate r_(DAP,i).

Cost Optimization for Block-and-Index Rate Structure

Power Block without Sell Back

Referring now to FIG. 12, a block diagram of a resource allocationsystem 1200 subject to a block-and-index rate structure is shown,according to an exemplary embodiment. In the resource allocation system1200, electricity is provided to a resource pool 1201 by a utilityprovider 1202 and generated on site via on-site generation 1204.Resources are consumed at a campus 1206. Resources are also consumed ata plant 1208, for example to generate steam, chilled water, and/orvarious other resources fed back into the resource pool 1201 via on-sitegeneration 1204. The utility provider 1202 provides power under ablock-and-index rate structure, as described with reference to FIGS.9-10.

The resource allocation system 1200 may therefore correspond to theenergy storage system 500 in FIG. 5. In some embodiments, the energystorage controller 506 of FIGS. 5-6 is used with the resource allocationsystem 1200 to allocate resources and load amongst the utility provider1202, on-site generation 1204, campus 1206, and plant 1208. In someembodiments, the planning tool 702 is used with the resource allocationsystem 1200 to predict energy/power costs and/or determine an optimalparticipation strategy in a block-and-index rate structure (e.g., todetermine an optimal block size B).

As illustrated by FIG. 12, a cost function for the block-and-index ratestructure may be developed by representing the utility provider as twoelectricity suppliers. In the system 1200, an electricity supplier B1210 provides electricity e_(b,i) corresponding to a fixed-price powerblock (e.g., blocks 904 and 906 of FIG. 9) at the block rate r_(b) whilean electricity supplier A 1212 provides electricity outside the block(i.e., e_(ind,i)) at the market rate r_(DAP). In the example shown, anpower connection 1203 is configured to obtain the power from the utilityprovider.

By representing the utility provider 1202 as a pair of electricitysuppliers 1210-1212, a total cost function (in a case without sell-back)may be formulated as a sum of a term for each of the electricitysuppliers 1210-1212. The cost associated with electricity supplier A1210 over h time steps is Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(ind,i). The costassociated with electricity supplier B 1212 over the same time period isΣ_(i=k) ^(k+h-1)r_(b)e_(b,i). Accordingly, the total cost for theutility provider 1202 may be expressed as J=Σ_(i=k)^(k+h-1)r_(DAP,i)e_(ind,i)+Σ_(i=k) ^(k+h-1)r_(b)e_(b,i).

In the case where the customer is not allowed to sell back power to theutility company, the customer will always purchase the full blockΣ_(i=k) ^(k+h-1)r_(b)e_(b,i)=Σ_(i=k) ^(k+h-1)r_(b)B. Accordingly, forthe sake of optimizing the cost associated with power consumption by thesystem 1200, the rate r_(b) can be assumed to be zero because nothingcan be done to affect the portion of the cost corresponding toelectricity supplier B 1210. Thus, the cost function remaining to beoptimized is J=Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(ind,i). Furthermore,additional constraints are added based on the representation of theproblem illustrated by FIG. 12. First, conservation of energy/power inthe system 1200 yieldse_(ind,i)+e_(b,i)=e_(plant,i)+e_(campus,i)−e_(gen,i) wherein e_(plant,i)is the amount of electricity consumed by the plant 1208 (e.g.,allocation for chillers, etc. to meet other campus loads), e_(campus,i)is the amount of electricity consumed by the campus 1206, and e_(gen,i)is the amount of on-site electricity generation 1210. Second, theblock-and-index rate structure requires the constraint e_(b,i)≤B, whereB is the predetermined block size.

This formulation of the cost function (i.e., J=Σ_(i=k)^(k+h-1)r_(DAP,i)e_(ind,i);e_(ind,i)+e_(b,i)=e_(plant,i)+e_(campus,i)−e_(gen,i), e_(b,i)≤B) canthen be fed into an optimization process to determine an optimalallocation of resources over an optimization period (e.g., from timestep k to time step k+h−1). For example, the cost function may be usedby the energy storage controller 506 and/or the planning tool 702.Various optimization processes are known, for example as described inU.S. patent application Ser. No. 15/473,496, filed Mar. 29, 2017,incorporated by reference herein in its entirety. Accordingly, anoptimal allocation of resources under a block-and-index rate structuremay be achieved by building a cost function by representing the utilityprovider as a first supplier that provides the predetermined block and asecond supplier that provides power above the block, setting the ratefor the second supplier to zero, and performing an optimization tominimize the resulting cost function.

Power Block with Sell Back

Still referring to FIG. 12, in some cases the customer is allowed tosell back to the market any unused power from the block (i.e.,B−e_(b,i)) at the market rate r_(DAP,i). In such a case, the termcorresponding to electricity supplier B 1210 accounts for the sell-back,becoming Σ_(i=k) ^(k+h-1)r_(DAP,i)(B−e_(b,i))+r_(b) e_(b,i). The totalcost function is then. J=Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(ind,i)−Σ_(i=k)^(k+h-1)r_(DAP,i)(B−e_(b,i))+r_(b)e_(b,i). In such a case, the costfunction can be rearranged as. J=−Σ_(i=k) ^(k+h-1)r_(DAP,i)B+Σ_(i=k)^(k+h-1)r_(DAP,i)(e_(IND,i)+e_(b,i))+r_(b) e_(b,i).

The cost function may then be further rewritten as J=−Σ_(i=k)^(k+h-1)r_(DAP,i)B+Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(import,i) r_(b) e_(b,i).Because the block size B is known the first term may be disregarded foroptimization purposes. Furthermore, as above an assumption of r_(b)=0may be made for optimization purposes, bringing the third term to zero.The resulting cost function is: J=Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(import,i).The cost function fora power block with sell-back rate structure therebyreduces to the cost function found for an hourly varying electricityrate structure.

Accordingly, in such a case, optimization may proceed as for an hourlyvarying electricity rate structure, for example as described in U.S.patent application Ser. No. 15/473,496, filed Mar. 29, 2017,incorporated by reference herein in its entirety. For example, the costfunction may be used by the energy storage controller 506 and/or theplanning tool 702.

Energy Block

Referring now to FIG. 13, a block diagram of a resource allocationsystem 1300 subject to a block-and-index rate structure is shown,according to an exemplary embodiment. In the resource allocation system1300, energy (e.g., in the form of a resource such as natural gas) isprovided to a resource pool 1301 by a utility provider 1302. Resourcesare consumed at a campus 1306. Resources are also consumed at a plant1308, for example to generate electricity or other resources fed backinto the resource pool 1301 via on-site generation 1304 (e.g., naturalgas may be used to generate electricity, steam, etc.). The utilityprovider 1302 provides energy under a block-and-index rate structure, asdescribed with reference to FIGS. 9-10.

The resource allocation system 1300 may therefore correspond to theenergy storage system 500 in FIG. 5. In some embodiments, the energystorage controller 506 of FIGS. 5-6 is used with the resource allocationsystem 1300 to allocate resources and load amongst the utility provider1302, on-site generation 1304, campus 1306, and plant 1308. In someembodiments, the planning tool 702 is used with the resource allocationsystem 1300 to predict energy/power costs and/or determine an optimalparticipation strategy in a block-and-index rate structure (e.g., todetermine an optimal block size B for a calendar period).

As illustrated by FIG. 13, a cost function for the block-and-index ratestructure may be developed by representing the utility provider as twoenergy suppliers. In the system 1300, an energy supplier B 1310 providesenergy corresponding to a fixed-price energy block (e.g., a set amountof an energy resource) at the block rate r_(b) while an electricitysupplier A 1312 provides energy outside the block (i.e., e_(ind,i)) atthe market rate r_(DAP). In the example shown, an energy connection 1303is configured to obtain the energy from the utility provider.

By representing the utility provider 1302 as a pair of energy suppliers1310-1312, a total cost function may be formulated as a sum of a termfor each of the energy suppliers 1310-1312. The cost associated withenergy supplier A 1310 over h time steps is Σ_(i=k)^(k+h-1)r_(DAP,i)e_(ind,i), where h is the length of an optimizationperiod. The cost associated with energy supplier B 1312 over the sametime period is Σ_(i=k) ^(k+h-1)r_(b) e_(b,i). Accordingly, the totalcost for the utility provider 1202 may be expressed as J=Σ_(i=k)^(k+h-1)r_(DAP,i)e_(ind,i)+Σ_(i=k) ^(k+h-1)r_(b)e_(b,i).

Because the block of the resource is always purchased under this ratestructure, for optimization purposes the block rate r_(b) can be assumedto be zero. Accordingly, the cost function for use in optimizationbecomes J=Σ_(i=k) ^(k+h-1)r_(DAP,i)e_(ind,i). The cost function issubject to a first constraint Σ_(i=k) ^(k+h-1) e_(b,i)≤B, which ensuresthat the sum of the energy provided by energy supplier B 1310 at eachtime step cannot exceed the total block amount B purchased for the wholetime period. The cost function is also subject to a second constrainte_(b,i)≥0 which ensures that energy cannot be sold back to the utilityprovider 1302.

As illustrated in FIG. 13, the optimization problem is substantiallysimilar to a system having energy storage equipment 1314 with a capacityequivalent to the energy block purchase (i.e., a capacity of B). Theenergy storage equipment 1314 is recharged to full capacity at thebeginning of a time period, using energy from energy supplier B 1310 atthe block price r_(b). In the optimization problem, a demand charge forenergy supplier B 1310 may be set to zero at the beginning of the periodto allow the battery to charge, and then set very high for the remainderof the time period to prevent charging later in the time period. Theenergy storage equipment 1314 may discharge at a different rate atdifferent time steps i.

This optimization problem (i.e., the cost function J=Σ_(i=k)^(k+h-1)r_(DAP,i)e_(ind,i), constraints Σ_(i=k) ^(k+h-1) e_(b,i)≤B ande_(b,i)≥0, etc.) may be used by the energy storage controller 506 foroptimization and online control and/or by the planning tool 702, forexample for determining an optimal participation strategy in theblock-and-index pricing scheme. Various optimization approaches arepossible, for example as described in U.S. patent application Ser. No.15/473,496, filed Mar. 29, 2017, incorporated by reference in itsentirety herein.

Block Size Optimization for Block and Index Rate Structure

Referring to FIGS. 12-13, the optimization problem described withreference thereto can also be formulated to determine the optimal blocksize in a planning tool framework (e.g., with planning tool 702). Theoptimization problem to be solved to determine the optimal block size Bhas the form J=Σ_(i=k) ^(k+h-1)r_(LMP,i)e_(ind,i)+Σ_(i=k)^(k+h-1)r_(b)e_(b,i)+r_(b)w_(b)B, where w_(b) is a weighting term. Theconstraints defined above with reference to FIGS. 12 and 13 still applyin corresponding embodiments, while r_(b) can be assumed to be zero asabove. This optimization problem can be solved using a similar approachas for a demand charge auxiliary variable, for example as described inU.S. patent application Ser. No. 15/405,236, filed Jan. 12, 2017,incorporated by reference in its entirety herein, or as for an assetsizing problem, for example as described in U.S. patent application Ser.No. 15/426,962, filed Feb. 7, 2017, incorporated by reference in itsentirety herein. That is, in some embodiments, a cost function isoptimized to determine the optimal size of the block as the size of theblock that minimizes the total cost of purchasing a resource from autility provider over an upcoming time period. This optimization mayfollow a stochastic approach to optimize the cost function over severalscenarios of possible loads and rates. Systems and methods relating tosuch stochastic scenarios are described in detail in U.S. patentapplication Ser. No. 16/115,290, filed Aug. 28, 2018, incorporated byreference herein in its entirety.

Cost Optimization for Load-Following-Block Rate Structure

Referring now to FIG. 14, a block diagram of a resource allocationsystem 1400 subject to a load-following-block rate structure is shown,according to an exemplary embodiment. In the resource allocation system1400, electricity is provided to a resource pool 1401 by a utilityprovider 1402 and generated on site via on-site generation 1404.Resources are consumed at a campus 1406. Resources are also consumed ata plant 1408, for example to generate electricity fed back into theresource pool 1401 via on-site generation 1404. The utility provider1402 provides power under a load-following-block rate structure, forexample as described with reference to FIG. 11.

The resource allocation system 1400 may therefore correspond to theenergy storage system 500 in FIG. 5. In some embodiments, the energystorage controller 506 of FIGS. 5-6 is used with the resource allocationsystem 1400 to allocate resources and load amongst the utility provider1402, on-site generation 1404, campus 1406, and plant 1408. In someembodiments, the planning tool 702 is used with the resource allocationsystem 1400 to predict energy/power costs and/or determine an optimalparticipation strategy in a load-following-block rate structure (e.g.,to determine an hedge percentage α_(h)).

As illustrated by FIG. 14, a cost function for the load-following-blockrate structure may be developed by representing the utility provider1402 as two electricity suppliers. In the system 1400, an electricitysupplier B 1410 provides electricity corresponding to a fixed-priceload-following block (e.g., blocks 1102 of FIG. 11) at the block rater_(LFB) while an electricity supplier A 1412 provides electricityoutside the block at the market rate r_(DAP). That is, electricitysupplier B 1410 supplies electricity α_(h)e_(import,i) while electricitysupplier A 1412 supplies electricity (1−α_(h))e_(import,i). In theexample shown, an energy connection 1403 is configured to obtain theenergy from the utility supplier.

By representing the utility provider 1402 as a pair of electricitysuppliers 1410-1412, a total cost function may be formulated as a sum ofa term for each of the electricity suppliers 1410-1412. The costassociated with electricity supplier A 1412 over h time steps is Σ_(i=k)^(k+h-1)(1−α_(h))r_(DAP,i)e_(import,i). The cost associated withelectricity supplier B 1410 over the same time period is Σ_(i=k)^(k+h-1)α_(h)r_(LFB)e_(import,i). Together, the total cost function isJ=Σ_(i=k) ^(k+h-1)α_(h)r_(LFB)e_(import,i)+Σ_(i=k)^(k+h-1)(1−α_(h))r_(DAP,i)e_(import,i). This can be reduced to J=Σ_(i=k)^(k+h-1)(α_(h)r_(LFB,f)+(1−α_(h))r_(DAP,i))e_(import,i). Accordingly,with a known hedging percentage α_(h) the load-following-block ratestructure translates to a mere rate adjustment of an hourly ratestructure. The optimization problem may thus be solved by the energystorage controller 506 or planning tool 702 using one or more processessuitable for optimization under an hourly rate structure, for example asdescribed in U.S. patent application Ser. No. 15/473,496, filed Mar. 29,2017, incorporated by reference herein in its entirety. Processes fordetermining an optimal hedging percentage α_(h) are shown in FIGS. 15-16and described in detail with reference thereto.

Load-Following-Block Hedge Percentage Optimization

Referring now to FIGS. 15-16, processes for determining a hedgingpercentage α_(h) are shown, according to exemplary embodiments. FIG. 15shows a flowchart of a process 1500 that takes an iterative narrowingapproach to locate an optimal hedging percentage. FIG. 16 shows aflowchart of an alternative process 1600 that uses a modeling approachto determine the optimal hedging percentage. The planning tool 702 maybe configured to execute process 1500 and/or process 1600.

Referring now to FIG. 15, the process 1500 starts at step 1502 wherethree hedge percentage values are picked as 0%, 50%, and 100%. Thestarting hedge percentage values thereby span the full range of possiblehedge percentages and bisect that range.

At step 1504, the planning tool 702 runs a simulation for a time period(e.g., a year) for each of the three hedge percentage values. A totalcost (e.g., a cost associated with the power/energy purchased under theload-following-block hedge rate structure) for the period is found foreach of the three hedge percentage values. At step 1506, the two lowestof the three total costs are determined, and the corresponding hedgepercentage values are selected. That is, the planning tool 702 selectsthe two hedge percentage values corresponding to the lowest two totalcosts and eliminates the hedge percentage value corresponding to thehighest total cost. This approach assumes that the two hedge percentagevalues corresponding to the lowest two costs are adjacent (i.e., 50% and100%, 0% and 50%, but not 0% and 100%).

At step 1508, a third hedge percentage value is set between the twohedge percentage values selected at step 1506. For example, if 50% and100% are selected at step 1506 (i.e., if 50% and 100% correspond to thetwo lowest total costs in the simulation of step 1504), a third hedgepercentage value is selected between 50% and 100%. In some embodiments,the third hedge percentage value may bisect the selected range (i.e.,75% in the preceding example).

At step 1510, the planning tool 702 checks whether a terminationcondition has been met. The termination condition may be based on adifference between two of the three selected values, for example suchthe termination condition is met if all three values are within athreshold range (e.g., 5%, 1%). In preferred embodiments, thetermination condition is not met on the first iteration.

If the termination condition is not met, the process 1500 returns tostep 1504, where a simulation is run for a time period for each of thethree selected hedge percentage values (i.e., the two values selected atstep 1506 and the third value selected at step 1508). A total cost isdetermined for each of the three values. At step 1506, the two valuescorresponding to lower total costs are again selected. At step 1508, athird percentage between those two values is set. The intervals betweenthe three values thereby decreases with each iteration through steps1504-1510.

After a number of iterations (e.g., 3, 5, 10), the termination conditionmay be met at step 1510. Once the termination condition is met, theprocess 1500 proceeds to step 1512. At step 1512, the planning tool 702runs a simulation over the time period and determines a total cost foreach of three percentage values. At step 1514, the percentage valuecorresponding to the lowest cost calculated at step 1512 is selected asthe recommended hedge percentage. The recommended hedge percentage maybe provided to a user via a graphical user interface.

Referring now to FIG. 16, an alternative process 1600 for determining arecommended hedge percentage is shown, according to an exemplaryembodiment. At step 1602, the planning tool 702 runs a simulation for atime period (e.g., one year) for each of a finite set of hedgepercentage values of various values between 0% and 100% (e.g., tenvalues, twenty values, fifty values). A total cost for the time periodis determined for each value in the finite set to generate a dataset ofhedge percentage values and corresponding total costs.

At step 1604, the correlation between hedge percentage value and totalcost is determined. That is, a model is fit to the dataset generated atstep 1604 that describes total cost as a function of hedge percentagevalue. The model may then be used to find the optimal hedge percentagewithout the need to rerun simulations over the time period (e.g.,without the need to run multiple one-year simulations), and without theneed for the process 1500 of FIG. 15.

At step 1606, an optimal hedge percentage is found using the correlationfound in step 1604. For example, a minimum of a function (model) thatdescribes total cost as a function of hedge percentage value may befound to identify a hedge percentage value between 0% and 100% thatminimizes cost. In some cases, a golden section search, gradient decent,Finonacci search, or Newton's method may be used to find the minimum ofthe model. The hedge percentage value that minimizes the total costusing the model is selected at the optimal/recommended hedge percentage.

At step 1608, the selected optimal/recommended hedge percentage isvalidated by selecting another set of hedge percentage values (i.e.,different values, in some embodiments including the optimal/recommendedhedge percentage) and running the simulation over the same time periodas in step 1602. Total costs generated from this new simulation may becompared to the model determined at step 1604 and the selectedoptimal/recommended hedge percentage. If the data generated at step 1608validates that the optimal/recommended hedge percentage approximatelycorresponds to a minimum total cost, process 1600 ends and that hedgepercentage is output as the recommended hedge percentage. If validationfails, the process 1600 may return to step 1604 where the new datasetmay be refit with a new model. Steps 1604 through 1608 may repeateduntil a recommended hedge percentage is validated. The recommended hedgepercentage may be provided to a user via a graphical user interfaceand/or automatically implemented by communicating the hedge percentageto a utility provider and controlling the equipment in accordance withoptimization at the recommended hedge percentage as described above.

In some embodiments, process 1500 and/or process 1600 may include astochastic approach. In such an embodiment, possible loads and possibleindex rates are generated for each of several scenarios for the timeperiod. The recommended hedge percentage may be chosen such that thecost function is minimized over all of the scenarios. Systems andmethods for generating such scenarios are described in detail in U.S.patent application Ser. No. 16/115,290, filed Aug. 28, 2018,incorporated by reference herein in its entirety.

Configuration of Exemplary Embodiments

The construction and arrangement of the systems and methods as shown inthe various exemplary embodiments are illustrative only. Although only afew embodiments have been described in detail in this disclosure, manymodifications are possible (e.g., variations in sizes, dimensions,structures, shapes and proportions of the various elements, values ofparameters, mounting arrangements, use of materials, colors,orientations, etc.). For example, the position of elements can bereversed or otherwise varied and the nature or number of discreteelements or positions can be altered or varied. Accordingly, all suchmodifications are intended to be included within the scope of thepresent disclosure. The order or sequence of any process or method stepscan be varied or re-sequenced according to alternative embodiments.Other substitutions, modifications, changes, and omissions can be madein the design, operating conditions and arrangement of the exemplaryembodiments without departing from the scope of the present disclosure.

The present disclosure contemplates methods, systems and programproducts on any machine-readable media for accomplishing variousoperations. The embodiments of the present disclosure can be implementedusing existing computer processors, or by a special purpose computerprocessor for an appropriate system, incorporated for this or anotherpurpose, or by a hardwired system. Embodiments within the scope of thepresent disclosure include program products comprising machine-readablemedia for carrying or having machine-executable instructions or datastructures stored thereon. Such machine-readable media can be anyavailable media that can be accessed by a general purpose or specialpurpose computer or other machine with a processor. By way of example,such machine-readable media can comprise RAM, ROM, EPROM, EEPROM, CD-ROMor other optical disk storage, magnetic disk storage or other magneticstorage devices, or any other medium which can be used to carry or storedesired program code in the form of machine-executable instructions ordata structures and which can be accessed by a general purpose orspecial purpose computer or other machine with a processor. Combinationsof the above are also included within the scope of machine-readablemedia. Machine-executable instructions include, for example,instructions and data which cause a general purpose computer, specialpurpose computer, or special purpose processing machines to perform acertain function or group of functions.

Although the figures show a specific order of method steps, the order ofthe steps may differ from what is depicted. Also two or more steps canbe performed concurrently or with partial concurrence. Such variationwill depend on the software and hardware systems chosen and on designerchoice. All such variations are within the scope of the disclosure.Likewise, software implementations could be accomplished with standardprogramming techniques with rule based logic and other logic toaccomplish the various connection steps, processing steps, comparisonsteps and decision steps.

What is claimed is:
 1. A building energy system comprising: equipmentoperable to consume, store, or generate one or more resources; a utilityconnection configured to obtain, from a utility provider, a firstresource of the one or more resources subject to a load-following-blockrate structure and provide the first resource to the equipment; and acontroller configured to: provide an objective function indicating atotal value of obtaining the first resource from the utility providerover a plurality of time steps, the objective function comprising afirst term representing a load-following-block of the first resourcefrom the utility provider as being sourced from a first supplier at afixed rate and further comprising a second term representing a remainderof the first resource from the utility provider as being sourced from asecond supplier at a variable rate; optimize the objective function togenerate values for one or more decision variables that indicate amountsof the one or more resources to store, generate, or consume at theplurality of time steps; and control the equipment to store, generate,or consume, at the plurality of time steps, the amounts of the one ormore resources indicated by the values of the one or more decisionvariables.
 2. The building energy system of claim 1, wherein theload-following-block is sized as a set proportion of a total amount ofthe first resource obtained from the utility provider.
 3. The buildingenergy system of claim 2, wherein the objective function comprises avalue of purchasing the first resource from the utility provider at agiven time step of the plurality of time steps as an adjusted ratemultiplied by an amount of the first resource obtained from the utilityprovider at the given time step.
 4. The building energy system of claim3, wherein the adjusted rate is defined based on the set proportion, thefixed rate, and the variable rate for the given time step.
 5. Thebuilding energy system of claim 2, wherein the controller is configuredto: determine an optimal proportion, the optimal proportion minimizingthe total value of purchasing the first resource from the utilityprovider over a given time period; and select the set proportion asequal to the optimal proportion.
 6. The building energy system of claim2, wherein the controller is configured to receive the set proportion asan input from a user.
 7. A method for operating equipment with abuilding energy system, comprising: operating equipment to consume,store, or generate one or more resources; receiving a first resource ofthe one or more resources from a utility provider subject to aload-following-block rate structure; providing the first resource to theequipment; allocating the one or more resources amongst the equipmentby: providing an objective function indicating a total value ofpurchasing the first resource from the utility provider over a pluralityof time steps, the objective function comprising a first termrepresenting a load-following-block of the first resource from theutility provider as being sourced from a first supplier at a fixed rate,and further comprising a second term representing a remainder of thefirst resource from the utility provider as sourced from a secondsupplier at a variable rate; and optimizing the objective function togenerate values for one or more decision variables that indicate amountsof the one or more resources to purchase, store, generate, or consume ateach of the plurality of time steps and controlling the equipment tostore, generate, or consume, at the plurality of time steps, the amountsof the one or more resources indicated by the values of the one or moredecision variables at each of the plurality of time steps.
 8. The methodof claim 7, wherein the load-following-block is sized as a proportion ofa total amount of the first resource obtained from the utility provider.9. The method of claim 8, wherein the objective function comprises avalue of purchasing the first resource from the utility provider at agiven time step of the plurality of time steps as an adjusted ratemultiplied by an amount of the first resource obtained from the utilityprovider at the given time step.
 10. The method of claim 8, wherein theadjusted rate is defined based on the proportion, the fixed rate, andthe variable rate for the given time step.
 11. The method of claim 8,comprising determining an optimal proportion, the optimal proportionminimizing the total value of purchasing the first resource from theutility provider over a given time period; and selecting the proportionas equal to the optimal proportion.
 12. The method of claim 8,comprising receiving the proportion as an input from a user.
 13. Amethod for determining a participation strategy for aload-following-block rate structure and controlling equipment inaccordance with the participation strategy, comprising: operating theequipment to consume, store, or generate one or more resources;receiving a first resource of the one or more resources from a utilityprovider subject to a load-following-block rate structure; providing anobjective function comprising a proportion for the load-following-blockrate structure as a decision variable, the objective function comprisinga value of receiving the first resource over a time period; determininga recommended proportion for the load-following-block rate structurethat minimizes a predicted value of operating the equipment over thetime period based on the objective function; generating controldecisions for the equipment based on the recommended proportion; andcontrolling the equipment with the control decisions to consume a totalamount of at least one of energy or power from the utility provider,wherein the recommended proportion of the total amount is priced at afixed rate and a remainder of the total amount is priced at a variablerate.
 14. The method of claim 13, wherein the objective functioncomprises the value of operating the equipment over the time period byproviding a simulation of the value over the time period.
 15. The methodof claim 13, wherein selecting the recommended proportion based on thetotal values comprises: selecting a plurality of percentages; evaluatingthe objective function for each percentage to determine a simulatedvalue for each percentage; fitting a model to the simulated values;determining the percentage that minimizes the predicted value byminimizing the model with respect to the percentage; and selecting therecommended proportion based on the percentage that minimizes thepredicted value.
 16. The method of claim 15, wherein minimizing themodel with respect to the percentage comprises performing at least oneof gradient descent, a golden section search, a Fibonacci search, orNewton's method.
 17. The method of claim 13, comprising generating aplurality of scenarios of possible loads and possible index rates forthe time period; wherein the recommended proportion minimizes the valueof operating the equipment for the time period over all of the pluralityof scenarios.
 18. The method of claim 17, wherein generating theplurality of possible loads and possible index rates for the time periodcomprises: storing a history of past scenarios comprising actual valuesfor historical loads and historical index rates; and at least one ofsampling the possible loads and possible index rates from the history ofpast scenarios; or generating an estimated distribution based on thehistory of past scenarios and sampling the possible loads and possibleindex rates from the estimated distribution.
 19. The method of claim 17,wherein generating the plurality of possible loads and possible indexrates for the time period comprises: receiving user input defininguser-defined loads and user-defined index rates for several scenarios;and at least one of sampling the possible loads and possible index ratesfrom the user-defined loads and user-defined rates; or generating anestimated distribution based on the user-defined loads and user-definedindex rate and sampling the possible loads and possible index rates fromthe estimated distribution.
 20. The method of claim 13, comprisingproviding the recommended proportion to a user via a graphical userinterface.